10-Q 1 q211aep10q.htm OHIO POWER COMPANY 2Q2011 10-Q Unassociated Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended June 30, 2011
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____

Commission
 
Registrants; States of Incorporation;
 
I.R.S. Employer
File Number
 
Address and Telephone Number
 
Identification Nos.
         
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
   
1 Riverside Plaza, Columbus, Ohio 43215-2373
   
   
Telephone (614) 716-1000
   

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

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

Indicate by check mark whether Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company have submitted electronically and posted on the AEP corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes
X
 
No
   

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

Indicate by check mark whether Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers or smaller reporting companies.  See the definitions of ‘large accelerated filer,’ ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
   
Accelerated filer
   
           
Non-accelerated filer
X
 
Smaller reporting company
   

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
Yes
   
No
X
 

Columbus Southern Power Company and Indiana Michigan Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

 
 

 

     
Number of shares of common stock outstanding of the registrants at
July 28, 2011
       
American Electric Power Company, Inc.
   
482,273,829
     
($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 OF QUARTERLY REPORTS ON FORM 10-Q
June 30, 2011
 
   
Page
Number
Glossary of Terms
 
i
     
Forward-Looking Information
 
iv
     
Part I. FINANCIAL INFORMATION
   
       
 
Items 1, 2 and 3 - Financial Statements, Management’s Discussion and Analysis and Quantitative and Qualitative Disclosures About Market Risk:
 
   
American Electric Power Company, Inc. and Subsidiary Companies:
   
 
Management’s Discussion and Analysis
 
1
 
Quantitative and Qualitative Disclosures About Market Risk
 
22
 
Condensed Consolidated Financial Statements
 
26
 
Index of Condensed Notes to Condensed Consolidated Financial Statements
 
31
       
Appalachian Power Company and Subsidiaries:
   
 
Management’s Discussion and Analysis
 
81
 
Quantitative and Qualitative Disclosures About Market Risk
 
89
 
Condensed Consolidated Financial Statements
 
90
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
95
       
Columbus Southern Power Company and Subsidiaries:
   
 
Management’s Narrative Discussion and Analysis
 
97
 
Quantitative and Qualitative Disclosures About Market Risk
 
103
 
Condensed Consolidated Financial Statements
 
104
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
109
       
Indiana Michigan Power Company and Subsidiaries:
   
 
Management’s Narrative Discussion and Analysis
 
111
 
Quantitative and Qualitative Disclosures About Market Risk
 
115
 
Condensed Consolidated Financial Statements
 
116
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
121
       
Ohio Power Company Consolidated:
   
 
Management’s Discussion and Analysis
 
123
 
Quantitative and Qualitative Disclosures About Market Risk
 
130
 
Condensed Consolidated Financial Statements
 
131
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
136
       
Public Service Company of Oklahoma:
   
 
Management’s Discussion and Analysis
 
138
 
Quantitative and Qualitative Disclosures About Market Risk
 
142
 
Condensed Financial Statements
 
143
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
148
       
Southwestern Electric Power Company Consolidated:
   
 
Management’s Discussion and Analysis
 
150
 
Quantitative and Qualitative Disclosures About Market Risk
 
155
 
Condensed Consolidated Financial Statements
 
156
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
161
 
 
 

 
       
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
162
       
Combined Management’s Discussion and Analysis of Registrant Subsidiaries
 
227
       
Controls and Procedures
 
238
         
Part II.  OTHER INFORMATION
   
     
 
Item 1.
Legal Proceedings
 
239
 
Item 1A.
Risk Factors
 
239
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
242
 
Item 5.
Other Information
 
243
 
Item 6.
Exhibits:
 
243
         
Exhibit 4(d)
   
         
Exhibit 4(e)
   
         
Exhibit 12
   
         
Exhibit 31(a)
   
         
Exhibit 31(b)
   
         
Exhibit 32(a)
   
         
Exhibit 32(b)
   
               
SIGNATURE
   
244

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., a holding company.
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 AEP Power 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.
AEPEP
 
AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, asset management and commercial and industrial sales in the deregulated Texas market.
AEPSC
 
American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
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.
BOA
 
Bank of America Corporation.
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, a transition charge applied to TCC’s transmission and distribution rates for stranded costs and other true-up amounts as required by the Texas Restructuring Legislation.
DCC Fuel
 
DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC, variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
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, an intrastate RTO.
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.

 
i

 


Term
 
Meaning
     
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 utility subsidiary.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KWH
 
Kilowatthour.
LPSC
 
Louisiana Public Service Commission.
MISO
 
Midwest Independent Transmission System Operator.
MMBtu
 
Million British Thermal Units.
MPSC
 
Michigan Public Service Commission.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
NEIL
 
Nuclear Electric Insurance Limited insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
AEP’s Nonutility Money Pool is the centralized funding mechanism AEP uses to meet the short term cash requirements of pool participants.
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.
PJM
 
Pennsylvania – New Jersey – Maryland, a RTO.
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, responsible for moving electricity over large interstate areas.
Sabine
 
Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity.
SEET
 
Significantly Excessive Earnings Test.
SIA
 
System Integration Agreement, effective June 15, 2000, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF
 
Spent Nuclear Fuel.
SO2
 
Sulfur Dioxide.
SPP
 
Southwest Power Pool, a RTO.
 
 
 
ii

 
Term
 
Meaning
     
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.
     
Transition Funding
 
AEP Texas Central Transition Funding I LLC and AEP Texas Central Transition Funding II LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas restructuring law.
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 is the centralized funding mechanism AEP uses to meet the short term cash requirements of pool participants.
VIE
 
Variable Interest Entity.
Virginia SCC
 
Virginia State Corporation Commission.
WPCo
 
Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC
 
Public Service Commission of West Virginia.

 
iii

 

FORWARD-LOOKING INFORMATION

This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Financial Discussion and Analysis” of the 2010 Annual Report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

·
The economic climate and growth in, or contraction within, our service territory and changes in market demand and demographic patterns.
·
Inflationary or deflationary interest rate trends.
·
Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·
The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
·
Electric load, customer growth and the impact of retail competition, particularly in Ohio.
·
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 resolve I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration and outage-related issues 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 lines and facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.
·
New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants.
·
Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
·
Resolution of litigation.
·
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.

 
iv

 


·
The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity 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.
·
Our ability to recover through rates or prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.
·
Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
·
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

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

 
v

 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Financial Results

Gross margins increased during the first six months of 2011 primarily due to successful rate proceedings in our various jurisdictions.  While our overall weather-related margins were slightly lower than 2010, cooling degree days and heating degree days were higher than normal throughout our service territories.

Regulatory Activity

Ohio 2009 – 2011 ESPs

In April 2011, the Supreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged resulting in three reversals, two of which may have a prospective impact through a remand proceeding.  Pursuant to a May 2011 PUCO order, CSPCo and OPCo implemented rates subject to refund.  Certain intervenors proposed adjustments that included a reduction of deferred FAC and other regulatory assets for the period prior to June 2011 of up to $634 million, excluding carrying costs, which management believes is without merit and violates the Supreme Court of Ohio decision.  The proposed adjustments also included refunds and rate reductions of related revenues beginning in June 2011 of up to $153 million.  See “Ohio Electric Security Plan Filings” section of Note 3.

Ohio January 2012 – May 2014 ESP

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The SSO presents redesigned generation rates by customer class.  Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013.  Under the new ESP, management estimates CSPCo and OPCo will have base generation revenue increases, excluding riders, of $17 million and $48 million, respectively, for 2012 and $46 million and $60 million, respectively, for 2013.  The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESPs could impact the outcome of the January 2012-May 2014 ESP, though the nature and extent of that impact is not presently known.  See “Ohio Electric Security Plan Filings” section of Note 3.

Ohio Distribution Base Rate Case

In February 2011, CSPCo and OPCo filed with the PUCO for annual increases in distribution rates of $34 million and $60 million, respectively.  The requested increase is based upon an 11.15% return on common equity to be effective January 2012.  In addition to the annual increases, CSPCo and OPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $216 million and $159 million, respectively, including carrying costs, to be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013.  See “2011 Ohio Distribution Base Rate Case” section of Note 3.

Virginia Regulatory Activity

In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012.  The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law. APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing.  If approved, APCo’s net base rate increase would be $75 million.  In July 2011, an Attorney General witness recommended an $80 million reduction in APCo’s requested rate year capacity charges.  See “2011 Virginia Biennial Base Rate Case” section of Note 3.
 
1

 

West Virginia Regulatory Activity

In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $51 million based upon a 10% return on common equity.  The order also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011.  See “Mountaineer Carbon Capture and Storage” section below.  In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and allowed APCo and WPCo to defer and amortize $15 million of previously expensed costs related to the 2010 cost reduction initiatives, each over a period of seven years.   See “2010 West Virginia Base Rate Case” section of Note 3.

Michigan Base Rate Case

In July 2011, I&M filed a request with the MPSC for an annual increase in Michigan base rates of $25 million and a return on equity of 11.15%.  The request includes an increase in depreciation rates that would result in a $6 million increase in depreciation expense.  I&M plans to request an interim rate increase, subject to refund, for the portion of the $25 million that excludes the depreciation rate changes and other regulatory amortizations effective in January 2012.  See “2011 Michigan Base Rate Case” section of Note 3.

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  SWEPCo’s share of construction costs is currently estimated to be $1.3 billion, excluding AFUDC, plus an additional $124 million for transmission, excluding AFUDC.  The APSC, LPSC and PUCT approved SWEPCo’s original application to build the Turk Plant.  In June 2010, the APSC issued an order which reversed and set aside the previously granted Certificate of Environmental Compatibility and Public Need.  Various proceedings are pending that challenge the Turk Plant’s construction and its approved wetlands and air permits.  In 2010, the motions for preliminary injunction were partially granted.  According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop.  Mitigation measures required by the permit are authorized and may be completed.  The preliminary injunction affects portions of the water intake and portions of two transmission lines.  In July 2011, the U.S. Eighth Circuit Court of Appeals affirmed the preliminary injunction.  Management is unable to predict the timing or the outcome related to this remand proceeding.

Management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service.  However, if SWEPCo is unable to complete the Turk Plant construction, including the related transmission facilities, and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.  See “Turk Plant” section of Note 3.

Ohio Customer Choice

In our Ohio service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service.  As a result, in comparison to the second quarter of 2010 and the first six months of 2010, we lost approximately $24 million and $43 million, respectively, of generation related gross margin.  We anticipate recovery of a portion of lost margins through off-system sales, including PJM capacity revenues, and our CRES provider.  Our CRES provider targets retail customers in Ohio, both within and outside of our retail service territory.

Cook Plant

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 $408 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
 
2

 
 
new turbine rotors.  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 reduce future net income and cash flows and impact financial condition.  See “Michigan 2009 and 2010 Power Supply Cost Recovery Reconciliations” section of Note 3 and “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

As a result of the nuclear plant situation in Japan following the March 2011 earthquake, we expect the Nuclear Regulatory Commission and possibly Congress to review safety procedures and requirements for nuclear generating facilities.  This review could increase procedures and testing requirements, require physical modifications to the plant and increase future operating costs at the Cook Plant.  We are unable to predict the impact of potential future regulation of nuclear facilities.

Texas Restructuring Appeals

Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020.  TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders.  TCC and intervenors appealed the PUCT’s true-up related orders.  After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Supreme Court of Texas.  In July 2011, the Supreme Court of Texas granted review and issued its opinion.  The PUCT’s order denying recovery of approximately $420 million in capacity auction true-up amounts was reversed.  We estimate that, in the remand to the PUCT, TCC will be entitled to recover approximately $420 million, plus interest from January 1, 2002.  See “Texas Restructuring Appeals” section of Note 3.

Mountaineer Carbon Capture and Storage

Product Validation Facility (PVF)

APCo and ALSTOM Power, Inc., 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 May 2011, the PVF ended operations and decommissioning of the facility began.

In APCo’s and WPCo’s May 2010 West Virginia base rate filing, APCo and WPCo requested rate base treatment of the PVF, including recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In March 2011, a WVPSC order denied the request for rate base treatment of the PVF largely due to its experimental operation.  The base rate order provided that should APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the PVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base.  As a result, APCo recorded a pretax write-off of $41 million ($26 million net of tax) in the first quarter of 2011.  As of June 30, 2011, APCo has recorded a noncurrent regulatory asset of $19 million related to the PVF.  If APCo cannot recover its remaining PVF investment and related accretion expenses, it would reduce future net income and cash flows.  See “Mountaineer Carbon Capture and Storage Project” section of Note 3.

Carbon Capture and Sequestration Project with the Department of Energy (DOE) (Commercial Scale Project)

 
During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility at the Mountaineer Plant.  AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project.  The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million.  In July 2011, management informed the DOE that it will complete a Front-End Engineering and Design study during the third quarter of 2011, but it is postponing any further CCS project activities because of the uncertainty about the regulation of CO2.  As of June 30, 2011, the project has incurred $30 million in total costs and has received $10 million of DOE eligible funding resulting in a $20 million net balance recorded in the Condensed Consolidated Balance Sheets.  Requests for recovery are in process in Michigan, Ohio and Virginia.  If the costs of the CCS project cannot be recovered, it would reduce future net income and cash flows.  See “Mountaineer Carbon Capture and Storage Project” section of Note 3.
 
3

 
LITIGATION

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot predict the eventual resolution, timing or 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, Note 6 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis” in the 2010 Annual Report.  Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies included herein.  Adverse results in these proceedings have the potential to materially affect our net income.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements.  We will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants from fossil fuel-fired power plants, new proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.
 
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 including the items discussed below and reductions of CO2 emissions to address concerns about global climate change.  See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Financial Discussion and Analysis” in the 2010 Annual Report.  We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  We should be able to recover these expenditures through market prices in deregulated jurisdictions.  If not, the costs of environmental compliance could adversely affect future net income, cash flows and possibly financial condition.

Update to Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of June 30, 2011, the AEP System had a total generating capacity of nearly 38,000 MWs, of which 23,900 MWs are coal-fired.  In the second quarter of 2011, we refined the cost estimates of complying with these rules and other impacts of the environmental proposals on our coal-fired generating facilities.  Based upon the updated estimates, investment to meet these proposed requirements ranges from approximately $6 billion to $8 billion between 2012 and 2020.  These amounts include investments to convert 1,070 MWs of coal generation to 932 MWs of natural gas capacity and build approximately 1,200 MWs of natural gas-fired generation.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules.  The cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose standards more stringent than the proposed rules, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on our units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.
 
4

 

Subject to the factors listed above and based upon our current evaluation, we may retire the following plants or units of plants before 2015:

 
 
 
Generating
Plant Name and Unit
 
Capacity
 
 
(in MWs)
Big Sandy Plant
 
 
 1,078 
Clinch River Plant, Unit 3
 
 
 235 
Conesville Plant, Unit 3
 
 
 165 
Glen Lyn Plant
 
 
 335 
Kammer Plant
 
 
 630 
Kanawha River Plant
 
 
 400 
Muskingum River Plant, Units 1-4
 
 
 840 
Philip Sporn Plant
 
 
 1,050 
Picway Plant
 
 
 100 
Tanners Creek Plant, Units 1-3
 
 
 495 
Welsh Plant, Unit 2
 
 
 528 
Total
 
 
 5,856 

Duke Energy Corporation, the operator of W. C. Beckjord Generating Station, has announced its intent to close the facility in 2015.  CSPCo owns 12.5% (54 MWs) of one unit at that station.

We are also considering the conversion of some of our coal units to natural gas, installing emission control equipment on other units and completing construction of the Turk and Dresden Plants.  Recovery of the remaining investments in facilities that may be closed will be subject to regulatory approval.

Cross State Air Pollution Rule (formerly the Clean Air Act Transport Rule)

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

In July 2011, the Federal EPA released the final rule, renamed the Cross State Air Pollution Rule (CSAP Rule).  Like the proposed Transport Rule, the CSAP Rule relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states.  Interstate trading of allowances is allowed on a restricted sub-regional basis beginning in 2012.  Arkansas, Louisiana and Oklahoma are subject only to the seasonal NOx program in the final rule.  However, Texas is now subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program.  The annual SO2 allowance budgets in Indiana, Ohio and West Virginia have been reduced significantly in the final rule.

The time frames and stringency of the required emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and our electric utility customers.  The compliance plan described above was based on the requirements of the proposed Transport Rule.  The more stringent requirements included in the final CSAP Rule could further accelerate unit retirements, increase capital requirements, constrain operations, decrease reliability and unfavorably impact financial condition if the increased costs are not recovered in rates or market prices.
 
5

 

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

The Federal EPA issued the Clean Air Mercury Rule (CAMR) in 2005, setting mercury emission standards for new coal-fired power plants and requiring all states to issue new state implementation plans including mercury requirements for existing coal-fired power plants.  The CAMR was vacated by the D.C. Circuit Court of Appeals in 2008.  In response, the Federal EPA has been developing a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The Federal EPA Administrator signed a proposed HAPs rule in March 2011, but the rule has not yet been published in the Federal Register.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrochloric acid (as a surrogate for acid gases) for units burning coal and oil, on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  Compliance is required within three years of the effective date of the final rule, which is expected by November 2011 per the Federal EPA’s settlement agreement with several environmental groups.  A one-year extension may be available if the extension is necessary for the installation of controls.  We are developing comments to submit to the Federal EPA and collecting additional information regarding the performance of our coal-fired units.  Comments will be accepted for 60 days after the rule is published in the Federal Register.

We will urge the Federal EPA to carefully consider all of the options available so that costly and inefficient control requirements are not imposed regardless of unit size, age or other operating characteristics.  We have older coal units for which it may be economically inefficient to install scrubbers or other environmental controls.  Several of these units are included in our current list of potential plant closures discussed above.

Regional Haze

In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze state implementation plan (SIP) submitted by the State of Oklahoma through the Department of Environmental Quality.  The Federal EPA is proposing to approve all of the NOx control measures in the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO.  The Federal EPA is proposing a federal implementation plan (FIP) that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP.  The proposal is open for public comment.

Coal Combustion Residual Rule

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

Currently, approximately 40% of the coal ash and other residual products from our generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses.  Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes.  In addition, we currently use surface impoundments and landfills to manage these materials at our generating facilities and will incur significant costs to upgrade or close and replace these existing facilities.  We estimate that the potential compliance costs associated with the proposed solid waste management alternative could be as high as $3.9 billion including AFUDC for units across the AEP System.  Regulation of these materials as hazardous wastes would significantly increase these costs.
 
6

 

Clean Water Act Regulations

In April 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling.  Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority.  We are evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at our facilities.  Comments on the proposal were due in July 2011.

Global Warming

While comprehensive economy-wide regulation of CO2 emissions might be mandated through new legislation, Congress has yet to enact such legislation.  The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA.  The Federal EPA issued a final endangerment finding for CO2 emissions from new motor vehicles in December 2009 and final rules for new motor vehicles in May 2010.  The Federal EPA determined that CO2 emissions from stationary sources will be subject to regulation under the CAA and finalized its proposed scheme to streamline and phase in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, state implementation plan calls and federal implementation plans.  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 and announced a settlement agreement to issue proposed new source performance standards for utility boilers that would be applicable for both new and existing utility boilers.  It is not possible at this time to estimate the costs of compliance with these new standards, but they may be material.

Our fossil fuel-fired generating units are very large sources of CO2 emissions.  If substantial CO2 emission reductions are required, there will be significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units.  To the extent we install additional controls on our generating plants to limit CO2 emissions and receive regulatory approvals to increase our rates, cost recovery could have a positive effect on future earnings.  Prudently incurred capital investments made by our subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment.  We would expect these principles to apply to investments made to address new environmental requirements.  However, requests for rate increases reflecting these costs can affect us adversely because our regulators could limit the amount or timing of increased costs that we would recover through higher rates.  In addition, to the extent our costs are relatively higher than our competitors’ costs, such as operators of nuclear and natural gas based 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 states, including Ohio, Michigan, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements.  We are taking steps to comply with these requirements.

Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others.  We have been named in pending lawsuits, which we are vigorously defending.  It is not possible to predict the outcome of these lawsuits or their impact on our operations or financial condition.  See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 4.
 
7

 

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 2010 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters – Global Warming” and “Management’s Financial Discussion and Analysis.”
 
RESULTS OF OPERATIONS

SEGMENTS

Our reportable segments and their related business activities are as follows:

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

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

Generation and Marketing
 
·
Wind farms and marketing and risk management activities primarily in ERCOT and, to a lesser extent, Ohio in PJM and MISO.

The table below presents our consolidated Net Income (Loss) by segment for the three and six months ended June 30, 2011 and 2010.

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2011
 
2010
 
2011
 
2010
 
 
(in millions)
 
Utility Operations
  $ 356     $ 132     $ 734     $ 476  
AEP River Operations
    (1 )     (1 )     6       2  
Generation and Marketing
    11       7       12       17  
All Other (a)
    (13 )     (1 )     (44 )     (12 )
Net Income
  $ 353     $ 137     $ 708     $ 483  

(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 settle and expire in the fourth quarter of 2011.
 
·
Revenue sharing related to the Plaquemine Cogeneration Facility which ends in the fourth quarter of 2011.

AEP CONSOLIDATED

Second Quarter of 2011 Compared to Second Quarter of 2010

Net Income increased from $137 million in 2010 to $353 million in 2011 primarily due to $185 million of expenses (net of tax) recorded in the second quarter of 2010 related to the cost reduction initiatives.

Average basic shares outstanding increased from 479 million in 2010 to 482 million in 2011.
 
8

 

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Net Income increased from $483 million in 2010 to $708 million in 2011 primarily due to $185 million of expenses (net of tax) recorded in the second quarter of 2010 related to the cost reduction initiatives.

Average basic shares outstanding increased from 479 million in 2010 to 482 million in 2011.  Actual shares outstanding were 482 million as of June 30, 2011.

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 total revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances and purchased power.

 
 
Three Months Ended
   
Six Months Ended
 
 
 
June 30,
   
June 30,
 
 
 
2011
   
2010
   
2011
   
2010
 
 
 
(in millions)
 
Revenues
  $ 3,389     $ 3,211     $ 6,913     $ 6,637  
Fuel and Purchased Power
    1,230       1,110       2,527       2,357  
Gross Margin
    2,159       2,101       4,386       4,280  
Depreciation and Amortization
    398       394       791       792  
Other Operating Expenses
    1,053       1,314       2,113       2,354  
Operating Income
    708       393       1,482       1,134  
Other Income, Net
    48       42       91       85  
Interest Expense
    227       237       459       472  
Income Tax Expense
    173       66       380       271  
Net Income
  $ 356     $ 132     $ 734     $ 476  

Summary of KWH Energy Sales for Utility Operations
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2011 
 
2010
 
2011 
 
2010 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
 
Residential
 13,503 
 
 
 12,659 
 
 30,452 
 
 30,433 
Commercial
 12,913 
 
 
 13,002 
 
 24,559 
 
 24,476 
Industrial
 15,153 
 
 
 14,662 
 
 29,482 
 
 28,044 
Miscellaneous
 777 
 
 
 783 
 
 1,500 
 
 1,495 
Total Retail (a)
 42,346 
 
 
 41,106 
 
 85,993 
 
 84,448 
 
 
 
 
 
 
 
 
 
Wholesale
 10,216 
 
 
 7,019 
 
 19,367 
 
 15,156 
 
 
 
 
 
 
 
 
 
Total KWHs
 52,562 
 
 
 48,125 
 
 105,360 
 
 99,604 
 
 
 
 
 
 
 
 
 
(a) Includes energy delivered to customers served by AEP's Texas wires companies.
 
 
9

 
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
June 30,
 
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in degree days)
Eastern Region
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 134 
 
 
 75 
 
 
 1,989 
 
 
 1,975 
Normal - Heating (b)
 
 168 
 
 
 170 
 
 
 1,907 
 
 
 1,911 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 368 
 
 
 434 
 
 
 371 
 
 
 434 
Normal - Cooling (b)
 
 295 
 
 
 289 
 
 
 299 
 
 
 293 
 
 
 
 
 
 
 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 10 
 
 
 5 
 
 
 702 
 
 
 764 
Normal - Heating (b)
 
 21 
 
 
 21 
 
 
 600 
 
 
 595 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (d)
 
 1,035 
 
 
 866 
 
 
 1,144 
 
 
 886 
Normal - Cooling (b)
 
 762 
 
 
 757 
 
 
 820 
 
 
 815 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

 
10

 

Second Quarter of 2011 Compared to Second Quarter of 2010
 
 
 
 
 
Reconciliation of Second Quarter of 2010 to Second Quarter of 2011
 
Net Income from Utility Operations
 
(in millions)
 
 
 
 
 
Second Quarter of 2010
  $ 132  
 
       
Changes in Gross Margin:
       
Retail Margins
    -  
Off-system Sales
    37  
Transmission Revenues
    13  
Other Revenues
    8  
Total Change in Gross Margin
    58  
 
       
Changes in Expenses and Other:
       
Other Operation and Maintenance
    258  
Depreciation and Amortization
    (4 )
Taxes Other Than Income Taxes
    3  
Interest and Investment Income
    (1 )
Carrying Costs Income
    (2 )
Allowance for Equity Funds Used During Construction
    4  
Interest Expense
    10  
Equity Earnings of Unconsolidated Subsidiaries
    5  
Total Change in Expenses and Other
    273  
 
       
Income Tax Expense
    (107 )
 
       
Second Quarter of 2011
  $ 356  

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 were unchanged primarily due to the following:
 
·
Successful rate proceedings in our service territories which include:
   
·
A $27 million rate increase for APCo.
   
·
An $18 million rate increase for KPCo.
   
·
A $7 million rate increase for SWEPCo.
   
·
A $6 million rate increase in Ohio.
   
·
A $6 million rate increase for I&M.
 
·
An $18 million increase in weather-related usage in our western region primarily due to a 20% increase in cooling degree days.
 
These increases were partially offset by:
 
·
A $24 million decrease attributable to Ohio customers switching to alternative competitive retail electric service (CRES) providers.
 
·
A $21 million decrease due to the expiration of E&R cost recovery in Virginia.
 
·
A $20 million increase in other variable electric generation expenses.
 
·
A $13 million decrease in weather-related usage in our eastern region primarily due to a 15% decrease in cooling degree days.
·
Margins from Off-system Sales increased $37 million primarily due to an increase in PJM capacity revenues and higher physical sales volumes.
·
Transmission Revenues increased $13 million primarily due to net rate increases in PJM.
·
Other Revenues increased $8 million primarily due to higher amortization of deferred gains.

 
11

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

·
Other Operation and Maintenance expenses decreased $258 million primarily due to:
 
·
A $278 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
 
·
A $54 million decrease due to the second quarter 2010 write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC.
 
·
A $6 million decrease in administrative and general expenses primarily due to a decrease in fringe benefit expenses.
 
These decreases were partially offset by:
 
·
A $27 million increase in storm-related expenses.
 
·
A $25 million increase due to the second quarter 2010 deferral of 2009 storm costs as allowed by the Virginia SCC.
 
·
A $17 million increase in demand side management expenses, energy efficiency program expenses and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
 
·
A $15 million increase in plant operating and maintenance expenses.
·
Depreciation and Amortization expenses increased $4 million primarily due to higher depreciable property balances partially offset by lower amortization due to the expiration of E&R amortization of deferred carrying costs in Virginia.
·
Taxes Other Than Income Taxes decreased $3 million primarily due to the employer portion of payroll taxes recorded in the second quarter of 2010 related to the cost reduction initiatives, partially offset by higher property taxes in 2011.
·
Allowance for Equity Funds Used During Construction increased $4 million primarily due to construction of the Dresden Plant and various environmental upgrades.
·
Interest Expense decreased $10 million primarily due to a decrease in long-term debt.
·
Equity Earnings of Unconsolidated Subsidiaries increased $5 million primarily due to an increase in transmission investments for ETT.
·
Income Tax Expense increased $107 million primarily due to an increase in pretax book income.

 
12

 

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010
 
 
 
 
 
Reconciliation of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2011
Net Income from Utility Operations
(in millions)
 
 
 
 
 
Six Months Ended June 30, 2010
 
$
 476 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
Retail Margins
 
 
 26 
 
Off-system Sales
 
 
 49 
 
Transmission Revenues
 
 
 21 
 
Other Revenues
 
 
 10 
 
Total Change in Gross Margin
 
 
 106 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
Other Operation and Maintenance
 
 
 244 
 
Depreciation and Amortization
 
 
 1 
 
Taxes Other Than Income Taxes
 
 
 (3)
 
Interest and Investment Income
 
 
 (1)
 
Carrying Costs Income
 
 
 (1)
 
Interest Expense
 
 
 13 
 
Equity Earnings of Unconsolidated Subsidiaries
 
 
 8 
 
Total Change in Expenses and Other
 
 
 261 
 
 
 
 
 
 
Income Tax Expense
 
 
 (109)
 
 
 
 
 
 
Six Months Ended June 30, 2011
 
$
 734 
 

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 $26 million primarily due to the following:
 
·
Successful rate proceedings in our service territories which include:
   
·
A $41 million rate increase in Ohio.
   
·
A $36 million rate increase for KPCo.
   
·
A $27 million rate increase for APCo.
   
·
A $20 million rate increase for SWEPCo.
   
·
A $15 million rate increase for I&M.
   
·
A $9 million net rate increase in our other jurisdictions.
 
·
A $12 million increase in weather-related usage in our western region primarily due to a 29% increase in cooling degree days.
 
These increases were partially offset by:
 
·
A $43 million decrease attributable to Ohio customers switching to alternative CRES providers.
 
·
A $37 million decrease in rate related margins for APCo due to the expiration of E&R cost recovery in Virginia.
 
·
A $27 million decrease in weather-related usage in our eastern region primarily due to a 15% decrease in cooling degree days.
 
·
An $8 million increase in other variable electric generation expenses.
·
Margins from Off-system Sales increased $49 million primarily due to an increase in PJM capacity revenues and higher physical sales volumes.
·
Transmission Revenues increased $21 million primarily due to net rate increases in PJM.
·
Other Revenues increased $10 million primarily due to higher amortization of deferred gains.

 
13

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

·
Other Operation and Maintenance expenses decreased $244 million primarily due to the following:
 
·
A $278 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
 
·
A $54 million decrease due to the second quarter 2010 write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC.
 
·
A $33 million decrease due to the first quarter 2011 deferral of 2010 costs related to storms and our cost reduction initiatives as allowed by the WVPSC.
 
·
A $24 million decrease in administrative and general expenses primarily due to a decrease in fringe benefit expenses.
 
·
An $11 million gain on the sale of land.
 
These decreases were partially offset by:
 
·
A $44 million increase in demand side management, energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
 
·
A $41 million increase due to the first quarter 2011 write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC.
 
·
A $29 million increase in storm-related expenses.
 
·
A $26 million increase in plant outage and other plant operating and maintenance expenses.
 
·
A $25 million increase due to the second quarter 2010 deferral of 2009 storm costs as allowed by the Virginia SCC.
·
Depreciation and Amortization expenses decreased $1 million due to the expiration of E&R amortization of deferred carrying costs in Virginia partially offset by higher depreciable property balances.
·
Taxes Other Than Income Taxes increased $3 million primarily due to higher property taxes in 2011 partially offset by the employer portion of payroll taxes recorded in the second quarter of 2010 related to the cost reduction initiatives.
·
Interest Expense decreased $13 million primarily due to a decrease in long-term debt.
·
Equity Earnings of Unconsolidated Subsidiaries increased $8 million primarily due to an increase in transmission investments for ETT.
·
Income Tax Expense increased $109 million primarily due to an increase in pretax book income, partially offset by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

AEP RIVER OPERATIONS

Second Quarter of 2011 Compared to Second Quarter of 2010

Net Income from our AEP River Operations segment was unchanged from 2010 to 2011.  AEP River had increases in revenues related to higher grain and coal exports and increased barge fleet size offset by increases in expenses related to higher fuel, maintenance and flood-related costs.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Net Income from our AEP River Operations segment increased from $2 million in 2010 to $6 million in 2011 primarily due to higher grain and coal exports, increased barge fleet size and the cost reduction initiatives recorded in the second quarter of 2010 partially offset by higher fuel, maintenance and flood-related costs.

GENERATION AND MARKETING

Second Quarter of 2011 Compared to Second Quarter of 2010

Net Income from our Generation and Marketing segment increased from $7 million in 2010 to $11 million in 2011 primarily due to increased inception gains from ERCOT marketing activities and increased income from our wind farm operations partially offset by lower gross margins at the Oklaunion Plant.
 
14

 

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Net Income from our Generation and Marketing segment decreased from $17 million in 2010 to $12 million in 2011 primarily due to lower gross margins at the Oklaunion Plant partially offset by increased income from our wind farm operations.

ALL OTHER

Second Quarter of 2011 Compared to Second Quarter of 2010

Net Income from All Other decreased from a loss of $1 million in 2010 to a loss of $13 million in 2011 primarily due to $16 million in pretax gains ($10 million, net of tax) on the sale of our remaining 138,000 shares of Intercontinental Exchange, Inc. (ICE) in the second quarter of 2010.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Net Income from All Other decreased from a loss of $12 million in 2010 to a loss of $44 million in 2011 due to a $22 million net of tax loss incurred in the first quarter 2011 settlement of litigation with BOA and Enron and a $16 million pretax gain ($10 million, net of tax) on the sale of our remaining 138,000 shares of ICE in the second quarter of 2010.

AEP SYSTEM INCOME TAXES

Second Quarter of 2011 Compared to Second Quarter of 2010

Income Tax Expense increased $109 million in comparison to 2010 primarily due to an increase in pretax book income.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Income Tax Expense increased $180 million in comparison to 2010 primarily due to an increase in pretax book income and the unrealized capital loss valuation allowance related to a deferred tax asset associated with the settlement of litigation with BOA and Enron, offset in part by the 2010 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.  Target debt to equity ratios are included in our credit arrangements as covenants that must be met for borrowing to continue.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

 
 
June 30, 2011
   
December 31, 2010
 
 
(dollars in millions)
Long-term Debt, including amounts due within one year
  $ 16,635       51.5 %   $ 16,811       52.8
%
Short-term Debt
    1,639       5.1       1,346       4.2  
Total Debt
    18,274       56.6       18,157       57.0  
Preferred Stock of Subsidiaries
    60       0.2       60       0.2  
AEP Common Equity
    13,939       43.2       13,622       42.8  
 
                               
Total Debt and Equity Capitalization
  $ 32,273       100.0 %   $ 31,839       100.0

Our ratio of debt-to-total capital decreased from 57% at December 31, 2010 to 56.6% at June 30, 2011.
 
15

 

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability.  We believe we have adequate liquidity under our existing credit facilities.  At June 30, 2011, we had $3 billion in aggregate credit facility commitments to support our operations.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  We are committed to maintaining adequate liquidity.  We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, sale-leaseback or leasing agreements or common stock.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At June 30, 2011, our available liquidity was approximately $2.3 billion as illustrated in the table below:

 
 
 
Amount
 
Maturity
 
 
 
(in millions)
 
 
Commercial Paper Backup:
 
 
 
 
 
 
Revolving Credit Facility
 
$
 1,454 
 
April 2012
 
Revolving Credit Facility
 
 
 1,500 
 
June 2013
Total
 
 
 2,954 
 
 
Cash and Cash Equivalents
 
 
 417 
 
 
Total Liquidity Sources
 
 
 3,371 
 
 
Less:
AEP Commercial Paper Outstanding
 
 
 944 
 
 
 
Letters of Credit Issued
 
 
 132 
 
 
 
 
 
 
 
 
 
Net Available Liquidity
 
$
 2,295 
 
 

We have credit facilities totaling $3 billion to support our commercial paper program.  The credit facilities allow us to issue letters of credit in an amount up to $1.35 billion.  In July 2011, we replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015.

In March 2011, we terminated a $478 million credit facility, used for letters of credit to support variable rate debt, that was scheduled to mature in April 2011.  In March 2011, we issued bilateral letters of credit to support the remarketing of $357 million of the variable rate debt and reacquired $115 million which are held by a trustee on our behalf.

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 six months of 2011 was $1.2 billion.  The weighted-average interest rate for our commercial paper during 2011 was 0.38%.

Securitized Accounts Receivables

In July 2011, we renewed our receivables securitization agreement.  The agreement provides a commitment of $750 million from bank conduits to purchase receivables with an increase to $800 million for the months of July, August and September to accommodate seasonal demand.  A commitment of $375 million with the seasonal increase to $425 million for the months of July, August and September expires in June 2012 and the remaining commitment of $375 million expires in June 2014.
 
16

 

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 capitalization is contractually defined in our revolving credit agreements.  Debt as defined in the revolving credit agreements excludes junior subordinated debentures, securitization bonds and debt of AEP Credit.  At June 30, 2011, this contractually-defined percentage was 52.3%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  At June 30, 2011, we complied with all of the covenants contained in these credit agreements.  In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements and in a majority of our non-exchange traded commodity contracts which would permit the lenders and counterparties to declare the outstanding amounts payable.  However, a default under our non-exchange traded commodity contracts does not cause an event of default under our revolving credit agreements.

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

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  At June 30, 2011, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.46 per share in July 2011.  Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time.  AEP’s income derives from our common stock equity in the earnings of our utility subsidiaries.  Various charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

We have the option to defer interest payments on the AEP Junior Subordinated Debentures for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.

We do not believe restrictions related to our various charter provisions and regulatory requirements will have any significant impact on Parent’s ability to access cash to meet the payment of dividends on its common stock.

Credit Ratings

We do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but our access to the commercial paper market may depend on our credit ratings.  In addition, downgrades in our credit ratings by one of the rating agencies could increase our borrowing costs.  Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject us to additional collateral demands under adequate assurance clauses under our derivative and non-derivative energy contracts.
 
17

 

CASH FLOW

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

 
Six Months Ended
 
 
June 30,
 
 
2011
 
2010
 
 
(in millions)
 
Cash and Cash Equivalents at Beginning of Period
  $ 294     $ 490  
Net Cash Flows from Operating Activities
    1,732       582  
Net Cash Flows Used for Investing Activities
    (1,280 )     (992 )
Net Cash Flows from (Used for) Financing Activities
    (329 )     758  
Net Increase in Cash and Cash Equivalents
    123       348  
Cash and Cash Equivalents at End of Period
  $ 417     $ 838  

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

Operating Activities
 
 
   
 
 
 
 
 
   
 
 
 
Six Months Ended
 
 
June 30,
 
 
2011
 
2010
 
 
(in millions)
 
Net Income
  $ 708     $ 483  
Depreciation and Amortization
    813       813  
Other
    211       (714 )
Net Cash Flows from Operating Activities
  $ 1,732     $ 582  

Net Cash Flows from Operating Activities were $1.7 billion in 2011 consisting primarily of Net Income of $708 million and $813 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 favorable impact of a decrease in fuel inventory and the unfavorable impact of reducing accounts payable and adjusting accrued taxes for a net operating loss and tax credit carryforward.  Deferred Income Taxes increased primarily due to provisions in the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Jobs Creation Act, the settlement with BOA and Enron and an increase in tax versus book temporary differences from operations.  In February 2011, we paid $425 million to BOA of which $211 million was used to settle litigation with BOA and Enron. The remaining $214 million was used to acquire cushion gas as discussed in Investing Activities below.
 
18

 

Net Cash Flows from Operating Activities were $582 million in 2010 consisting primarily of Net Income of $483 million and $813 million of noncash Depreciation and Amortization.  Other includes a $656 million increase in securitized receivables under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement.  Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Significant changes in other items include an increase in under-recovered fuel primarily due to the deferral of fuel under the FAC in Ohio and higher fuel costs in Oklahoma, accrued tax benefits and the favorable impact of a decrease in fuel inventory.  Deferred Income Taxes increased primarily due to the American Recovery and Reinvestment Act of 2009 extending bonus depreciation provisions, a change in tax accounting method and an increase in tax versus book temporary differences from operations.
 
 
Investing Activities
 
 
   
 
 
 
 
 
   
 
 
 
Six Months Ended
 
 
June 30,
 
 
2011
 
2010
 
 
(in millions)
 
Construction Expenditures
  $ (1,113 )   $ (1,104 )
Acquisitions of Nuclear Fuel
    (93 )     (41 )
Acquisition of Cushion Gas from BOA
    (214 )     -  
Proceeds from Sales of Assets
    94       147  
Other
    46       6  
Net Cash Flows Used for Investing Activities
  $ (1,280 )   $ (992 )

Net Cash Flows Used for Investing Activities were $1.3 billion in 2011 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments.  We paid $214 million to BOA for cushion gas as part of a litigation settlement.

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

Financing Activities
 
 
   
 
 
 
 
 
   
 
 
 
Six Months Ended
 
 
June 30,
 
 
2011
 
2010
 
 
(in millions)
 
Issuance of Common Stock, Net
  $ 49     $ 42  
Issuance/Retirement of Debt, Net
    104       1,166  
Dividends Paid on Common Stock
    (446 )     (399 )
Other
    (36 )     (51 )
Net Cash Flows from (Used for) Financing Activities
  $ (329 )   $ 758  

Net Cash Flows Used for Financing Activities in 2011 were $329 million.  Our net debt issuances were $104 million. The net issuances included issuances of $600 million of senior unsecured notes, $481 million of pollution control bonds and an increase in short-term borrowing of $293 million offset by retirements of $578 million of senior unsecured and debt notes, $591 million of pollution control bonds and $92 million of securitization bonds.  We paid common stock dividends of $446 million.  See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retirements.
 
19

 

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

In July 2011, AEGCo remarketed $45 million of variable rate Pollution Control Bonds which may be tendered for purchase at the option of the holder.  The Pollution Control Bonds are supported by letters of credit which expire in 2014.

In July 2011, I&M retired $2 million of Notes Payable related to DCC Fuel.

In July 2011, SWEPCo retired $41 million of 4.5% Pollution Control Bonds due in 2011.

OFF-BALANCE SHEET ARRANGEMENTS

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

 
 
 
 
June 30,
 
December 31,
 
 
 
 
2011 
 
2010 
 
 
 
 
(in millions)
 
Rockport Plant Unit 2 Future Minimum Lease Payments
 
$
 1,700 
 
$
 1,774 
 
Railcars Maximum Potential Loss From Lease Agreement
 
 
 25 
 
 
 25 

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” in the 2010 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2010 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

MINE SAFETY INFORMATION

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations.  The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters.  SWEPCo, through its ownership of DHLC, CSPCo, through its ownership of Conesville Coal Preparation Company (CCPC), and OPCo, through its use of the Conner Run fly ash impoundment, are subject to the provisions of the Mine Act.
 
20

 

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act.  DHLC, CCPC and Conner Run received the following notices of violation and proposed assessments under the Mine Act for the quarter ended June 30, 2011:

 
 
 
DHLC
 
CCPC
 
Conner Run
Number of Citations for Violations of Mandatory Health or
 
 
 
 
 
 
 
 
 
 
Safety Standards under 104 *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Orders Issued under 104(b) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Citations and Orders for Unwarrantable Failure
 
 
 
 
 
 
 
 
 
 
to Comply with Mandatory Health or Safety Standards under 104(d) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Flagrant Violations under 110(b)(2) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Imminent Danger Orders Issued under 107(a) *
 
 
 - 
 
 
 - 
 
 
 - 
Total Dollar Value of Proposed Assessments
 
$
 1,123 
 
$
 400 
 
$
 - 
Number of Mining-related Fatalities
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
 
 
 
 
 
 
 
* References to sections under the Mine Act
 
 
 
 
 
 
 
 
 

DHLC currently has three legal actions pending before the Federal Mine Safety and Health Review Commission. Two are related to actions challenging four violations issued by Mine Safety and Health Administration following an employee fatality in March 2009 and the third legal action is challenging a citation issued in August 2010 related to a dragline boom issue.

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” in the 2010 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

Pronouncements Effective in the Future

The FASB issued ASU 2011-05 “Presentation of Comprehensive Income” eliminating the option to present the components of other comprehensive income as a part of the statement of shareholders’ equity.  The standard requires other comprehensive income be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income.  This standard will change the presentation of our financial statements but will not affect the calculation of net income, comprehensive income or earnings per share.  We will retrospectively adopt ASU 2011-05 effective January 1, 2012.

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, financial statements, contingencies, financial instruments, emission allowances, 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.
 
21

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

Our Utility Operations segment is exposed to certain market risks as a major power producer and through its transactions in wholesale electricity, coal and emission allowance trading and marketing contracts.  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 and, to a lesser extent, Ohio in PJM and MISO, primarily transacts in wholesale energy 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 settle and expire in the fourth quarter of 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 power, coal and natural gas and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk 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 President, 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.
 
22

 

The following table summarizes the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2010:

MTM Risk Management Contract Net Assets (Liabilities)
 
Six Months Ended June 30, 2011
 
 
 
 
 
 
   
Generation
   
 
   
 
 
 
 
Utility
   
and
   
 
   
 
 
 
 
Operations
   
Marketing
   
All Other
   
Total
 
 
 
(in millions)
 
Total MTM Risk Management Contract Net Assets
 
 
   
 
   
 
   
 
 
at December 31, 2010
  $ 91     $ 140     $ 2     $ 233  
(Gain) Loss from Contracts Realized/Settled During the Period and
                               
Entered in a Prior Period
    (11 )     (14 )     (1 )     (26 )
Fair Value of New Contracts at Inception When Entered During the
                               
Period (a)
    3       7       -       10  
Net Option Premiums Received for Unexercised or Unexpired
                               
Option Contracts Entered During the Period
    -       -       -       -  
Changes in Fair Value Due to Market Fluctuations During the
                               
Period (b)
    4       10       -       14  
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
    3       -       -       3  
Total MTM Risk Management Contract Net Assets
                               
at June 30, 2011
  $ 90     $ 143     $ 1       234  
 
                               
Commodity Cash Flow Hedge Contracts
                            19  
Interest Rate and Foreign Currency Cash Flow Hedge Contracts
                            (2 )
Fair Value Hedge Contracts
                            8  
Collateral Deposits
                            39  
Total MTM Derivative Contract Net Assets at June 30, 2011
                          $ 298  

(a)
Reflects fair value on primarily 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)
Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)
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.
 
23

 

Credit Risk

We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  We use Moody’s Investors Service, Standard & Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

We have risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily.  As of June 30, 2011, our credit exposure net of collateral to sub investment grade counterparties was approximately 7.35%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).  As of June 30, 2011, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

 
 
 
Exposure
 
 
 
 
 
Number of
 
Net Exposure
 
 
Before
 
 
Counterparties
of
 
 
Credit
Credit
Net
>10% of
Counterparties
Counterparty Credit Quality
Collateral
Collateral
Exposure
Net Exposure
>10%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in millions, except number of counterparties)
Investment Grade
 
$
 591 
 
$
 5 
 
$
 586 
 
 
 1 
 
$
 173 
Split Rating
 
 
 1 
 
 
 - 
 
 
 1 
 
 
 1 
 
 
 1 
Noninvestment Grade
 
 
 7 
 
 
 4 
 
 
 3 
 
 
 2 
 
 
 3 
No External Ratings:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Internal Investment Grade
 
 
 207 
 
 
 1 
 
 
 206 
 
 
 2 
 
 
 90 
 
Internal Noninvestment Grade
 
 
 72 
 
 
 12 
 
 
 60 
 
 
 1 
 
 
 31 
Total as of June 30, 2011
 
$
 878 
 
$
 22 
 
$
 856 
 
 
 7 
 
$
 298 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total as of December 31, 2010
 
$
 946 
 
$
 33 
 
$
 913 
 
 
 7 
 
$
 347 

Value at Risk (VaR) Associated with Risk Management Contracts

We use a risk measurement model, which calculates VaR, to measure our commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, as of June 30, 2011, 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.
 
24

 

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

VaR Model

Six Months Ended
 
Twelve Months Ended
June 30, 2011
 
December 31, 2010
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
(in millions)
 
(in millions)
$
 
$
 
$
 
$
 
$
 
$
 
$
 
$

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 movements 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 our interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on debt outstanding as of June 30, 2011 and December 31, 2010, the estimated EaR on our debt portfolio for the following twelve months was $27 million and $5 million, respectively.

 
25

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
For the Three and Six Months Ended June 30, 2011 and 2010
 
(in millions, except per-share and share amounts)
 
(Unaudited)
 
 
 
 
   
 
   
 
   
 
 
 
 
Three Months Ended
   
Six Months Ended
 
 
 
2011
   
2010
   
2011
   
2010
 
REVENUES
 
 
   
 
   
 
   
 
 
Utility Operations
  $ 3,360     $ 3,186     $ 6,857     $ 6,592  
Other Revenues
    249       174       482       337  
TOTAL REVENUES
    3,609       3,360       7,339       6,929  
EXPENSES
                               
Fuel and Other Consumables Used for Electric Generation
    980       895       2,036       1,909  
Purchased Electricity for Resale
    287       227       562       465  
Other Operation
    697       994       1,383       1,667  
Maintenance
    316       243       581       514  
Depreciation and Amortization
    410       405       813       813  
Taxes Other Than Income Taxes
    202       202       415       409  
TOTAL EXPENSES
    2,892       2,966       5,790       5,777  
 
                               
OPERATING INCOME
    717       394       1,549       1,152  
 
                               
Other Income (Expense):
                               
Interest and Investment Income
    3       18       5       21  
Carrying Costs Income
    17       19       32       33  
Allowance for Equity Funds Used During Construction
    23       19       43       43  
Interest Expense
    (239 )     (249 )     (481 )     (499 )
 
                               
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
    521       201       1,148       750  
 
                               
Income Tax Expense
    174       65       452       272  
Equity Earnings of Unconsolidated Subsidiaries
    6       1       12       5  
 
                               
NET INCOME
    353       137       708       483  
 
                               
Less:  Net Income Attributable to Noncontrolling Interests
    1       1       2       2  
 
                               
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS
    352       136       706       481  
 
                               
Less: Preferred Stock Dividend Requirements of Subsidiaries
    -       -       1       1  
 
                               
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
  $ 352     $ 136     $ 705     $ 480  
 
                               
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
    481,928,494       479,050,774       481,538,549       478,741,871  
 
                               
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
  $ 0.73     $ 0.28     $ 1.46     $ 1.00  
 
                               
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
    482,203,255       479,176,543       481,786,698       479,012,304  
 
                               
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
  $ 0.73     $ 0.28     $ 1.46     $ 1.00  
 
                               
CASH DIVIDENDS DECLARED PER SHARE
  $ 0.46     $ 0.42     $ 0.92     $ 0.83  
 
                               
See Condensed Notes to Condensed Consolidated Financial Statements.
                               

 
26

 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND
COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2011 and 2010
(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, 2009
 
 498 
 
$
 3,239 
 
$
 5,824 
 
$
 4,451 
 
$
 (374)
 
$
 - 
 
$
 13,140 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Common Stock
 
 2 
 
 
 9 
 
 
 34 
 
 
 
 
 
 
 
 
 
 
 
 43 
Common Stock Dividends
 
 
 
 
 
 
 
 
 
 
 (398)
 
 
 
 
 
 (1)
 
 
 (399)
Preferred Stock Dividend Requirements of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Subsidiaries
 
 
 
 
 
 
 
 
 
 
 (1)
 
 
 
 
 
 
 
 
 (1)
Other Changes in Equity
 
 
 
 
 
 
 
 2 
 
 
 
 
 
 
 
 
 
 
 
 2 
SUBTOTAL – EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 12,785 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $1
 
 
 
 
 
 
 
 
 
 
 
 
 
 2 
 
 
 
 
 
 2 
 
 
Securities Available for Sale, Net of Tax of $6
 
 
 
 
 
 
 
 
 
 
 
 
 
 (11)
 
 
 
 
 
 (11)
 
 
Amortization of Pension and OPEB Deferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Costs, Net of Tax of $6
 
 
 
 
 
 
 
 
 
 
 
 
 
 11 
 
 
 
 
 
 11 
NET INCOME
 
 
 
 
 
 
 
 
 
 
 481 
 
 
 
 
 
 2 
 
 
 483 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 485 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – JUNE 30, 2010
 
 500 
 
$
 3,248 
 
$
 5,860 
 
$
 4,533 
 
$
 (372)
 
$
 1 
 
$
 13,270 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – DECEMBER 31, 2010
 
 501 
 
$
 3,257 
 
$
 5,904 
 
$
 4,842 
 
$
 (381)
 
$
 - 
 
$
 13,622 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Common Stock
 
 1 
 
 
 9 
 
 
 40 
 
 
 
 
 
 
 
 
 
 
 
 49 
Common Stock Dividends
 
 
 
 
 
 
 
 
 
 
 (444)
 
 
 
 
 
 (2)
 
 
 (446)
Preferred Stock Dividend Requirements of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Subsidiaries
 
 
 
 
 
 
 
 
 
 
 (1)
 
 
 
 
 
 
 
 
 (1)
Other Changes in Equity
 
 
 
 
 
 
 
 (12)
 
 
 
 
 
 
 
 
 
 
 
 (12)
SUBTOTAL – EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 13,212 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $3
 
 
 
 
 
 
 
 
 
 
 
 
 
 6 
 
 
 
 
 
 6 
 
 
Securities Available for Sale, Net of Tax of $-
 
 
 
 
 
 
 
 
 
 
 
 
 
 1 
 
 
 
 
 
 1 
 
 
Amortization of Pension and OPEB Deferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Costs, Net of Tax of $6
 
 
 
 
 
 
 
 
 
 
 
 
 
 12 
 
 
 
 
 
 12 
NET INCOME
 
 
 
 
 
 
 
 
 
 
 706 
 
 
 
 
 
 2 
 
 
 708 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 727 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – JUNE 30, 2011
 
 502 
 
$
 3,266 
 
$
 5,932 
 
$
 5,103 
 
$
 (362)
 
$
 - 
 
$
 13,939 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 

 
27

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2011 and December 31, 2010
(in millions)
(Unaudited)
 
 
 
2011 
 
2010 
CURRENT ASSETS
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 417 
 
$
 294 
Other Temporary Investments
 
 
 
 
 
 
 
(June 30, 2011 and December 31, 2010 amounts include $250 and $287, respectively, related to Transition Funding and EIS)
 
 
 311 
 
 
 416 
Accounts Receivable:
 
 
 
 
 
 
 
Customers
 
 
 711 
 
 
 683 
 
Accrued Unbilled Revenues
 
 
 74 
 
 
 195 
 
Pledged Accounts Receivable - AEP Credit
 
 
 1,023 
 
 
 949 
 
Miscellaneous
 
 
 95 
 
 
 137 
 
Allowance for Uncollectible Accounts
 
 
 (37)
 
 
 (41)
 
 
Total Accounts Receivable
 
 
 1,866 
 
 
 1,923 
Fuel
 
 
 680 
 
 
 837 
Materials and Supplies
 
 
 625 
 
 
 611 
Risk Management Assets
 
 
 173 
 
 
 232 
Accrued Tax Benefits
 
 
 331 
 
 
 389 
Regulatory Asset for Under-Recovered Fuel Costs
 
 
 93 
 
 
 81 
Margin Deposits
 
 
 86 
 
 
 88 
Prepayments and Other Current Assets
 
 
 172 
 
 
 145 
TOTAL CURRENT ASSETS
 
 
 4,754 
 
 
 5,016 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
Generation
 
 
 24,841 
 
 
 24,352 
 
Transmission
 
 
 8,779 
 
 
 8,576 
 
Distribution
 
 
 14,465 
 
 
 14,208 
Other Property, Plant and Equipment (including nuclear fuel and coal mining)
 
 
 3,870 
 
 
 3,846 
Construction Work in Progress
 
 
 2,714 
 
 
 2,758 
Total Property, Plant and Equipment
 
 
 54,669 
 
 
 53,740 
Accumulated Depreciation and Amortization
 
 
 18,605 
 
 
 18,066 
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET
 
 
 36,064 
 
 
 35,674 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
Regulatory Assets
 
 
 5,004 
 
 
 4,943 
Securitized Transition Assets
 
 
 1,673 
 
 
 1,742 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 1,574 
 
 
 1,515 
Goodwill
 
 
 76 
 
 
 76 
Long-term Risk Management Assets
 
 
 343 
 
 
 410 
Deferred Charges and Other Noncurrent Assets
 
 
 1,264 
 
 
 1,079 
TOTAL OTHER NONCURRENT ASSETS
 
 
 9,934 
 
 
 9,765 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 50,752 
 
$
 50,455 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
28

 
 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2011 and December 31, 2010
(dollars in millions)
(Unaudited)
 
 
 
2011 
 
2010 
CURRENT LIABILITIES
 
 
Accounts Payable
 
$
 969 
 
$
 1,061 
Short-term Debt:
 
 
 
 
 
 
 
Securitized Debt for Receivables - AEP Credit
 
 
 
 695 
 
 
 690 
 
Other Short-term Debt
 
 
 
 944 
 
 
 656 
 
 
Total Short-term Debt
 
 
 
 1,639 
 
 
 1,346 
Long-term Debt Due Within One Year
 
 
 1,071 
 
 
 1,309 
Risk Management Liabilities
 
 
 94 
 
 
 129 
Customer Deposits
 
 
 284 
 
 
 273 
Accrued Taxes
 
 
 597 
 
 
 702 
Accrued Interest
 
 
 282 
 
 
 281 
Regulatory Liability for Over-Recovered Fuel Costs
 
 
 9 
 
 
 17 
Deferred Gain and Accrued Litigation Costs
 
 
 - 
 
 
 448 
Other Current Liabilities
 
 
 942 
 
 
 952 
TOTAL CURRENT LIABILITIES
 
 
 5,887 
 
 
 6,518 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
Long-term Debt
 
 
 
 
 
 
 
(June 30, 2011 and December 31, 2010 amounts include $1,703 and $1,857, respectively, related to Transition Funding, DCC Fuel and Sabine)
 
 
 15,564 
 
 
 15,502 
Long-term Risk Management Liabilities
 
 
 124 
 
 
 141 
Deferred Income Taxes
 
 
 7,716 
 
 
 7,359 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 3,246 
 
 
 3,171 
Asset Retirement Obligations
 
 
 1,429 
 
 
 1,394 
Employee Benefits and Pension Obligations
 
 
 1,790 
 
 
 1,893 
Deferred Credits and Other Noncurrent Liabilities
 
 
 997 
 
 
 795 
TOTAL NONCURRENT LIABILITIES
 
 
 30,866 
 
 
 30,255 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 36,753 
 
 
 36,773 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
 
 
 60 
 
 
 60 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
Commitments and Contingencies (Note 4)
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY
 
 
 
 
 
 
Common Stock – Par Value – $6.50 Per Share:
 
 
 
 
 
 
 
 
 
2011 
 
2010 
 
 
 
 
 
 
 
 
Shares Authorized
600,000,000 
 
600,000,000 
 
 
 
 
 
 
 
 
Shares Issued
502,534,747 
 
501,114,881 
 
 
 
 
 
 
 
(20,307,725 shares were held in treasury at June 30, 2011 and December 31, 2010)
 
 
 3,266 
 
 
 3,257 
Paid-in Capital
 
 
 5,932 
 
 
 5,904 
Retained Earnings
 
 
 5,103 
 
 
 4,842 
Accumulated Other Comprehensive Income (Loss)
 
 
 (362)
 
 
 (381)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY
 
 
 13,939 
 
 
 13,622 
 
 
 
 
 
 
 
TOTAL EQUITY
 
 
 13,939 
 
 
 13,622 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 
$
 50,752 
 
$
 50,455 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements.
 
 
 
 
 
 

 
29

 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2011 and 2010
(in millions)
(Unaudited)
 
 
 
2011 
 
2010 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net Income
 
$
 708 
 
$
 483 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 813 
 
 
 813 
 
Deferred Income Taxes
 
 
 525 
 
 
 212 
 
Gain on Settlement with BOA and Enron
 
 
 (51)
 
 
 - 
 
Settlement of Litigation with BOA and Enron
 
 
 (211)
 
 
 - 
 
Carrying Costs Income
 
 
 (32)
 
 
 (33)
 
Allowance for Equity Funds Used During Construction
 
 
 (43)
 
 
 (43)
 
Mark-to-Market of Risk Management Contracts
 
 
 61 
 
 
 4 
 
Amortization of Nuclear Fuel
 
 
 72 
 
 
 69 
 
Property Taxes
 
 
 62 
 
 
 54 
 
Fuel Over/Under-Recovery, Net
 
 
 (93)
 
 
 (181)
 
Change in Other Noncurrent Assets
 
 
 (11)
 
 
 (21)
 
Change in Other Noncurrent Liabilities
 
 
 83 
 
 
 65 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 53 
 
 
 (802)
 
 
Fuel, Materials and Supplies
 
 
 146 
 
 
 71 
 
 
Accounts Payable
 
 
 (87)
 
 
 (168)
 
 
Accrued Taxes, Net
 
 
 (198)
 
 
 (164)
 
 
Other Current Assets
 
 
 (9)
 
 
 66 
 
 
Other Current Liabilities
 
 
 (56)
 
 
 157 
Net Cash Flows from Operating Activities
 
 
 1,732 
 
 
 582 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
Construction Expenditures
 
 
 (1,113)
 
 
 (1,104)
Change in Other Temporary Investments, Net
 
 
 11 
 
 
 31 
Purchases of Investment Securities
 
 
 (645)
 
 
 (838)
Sales of Investment Securities
 
 
 712 
 
 
 849 
Acquisitions of Nuclear Fuel
 
 
 (93)
 
 
 (41)
Acquisitions of Assets
 
 
 (10)
 
 
 (12)
Acquisition of Cushion Gas from BOA
 
 
 (214)
 
 
 - 
Proceeds from Sales of Assets
 
 
 94 
 
 
 147 
Other Investing Activities
 
 
 (22)
 
 
 (24)
Net Cash Flows Used for Investing Activities
 
 
 (1,280)
 
 
 (992)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Issuance of Common Stock, Net
 
 
 49 
 
 
 42 
Issuance of Long-term Debt
 
 
 1,074 
 
 
 1,161 
Commercial Paper and Credit Facility Borrowings
 
 
 357 
 
 
 50 
Change in Short-term Debt, Net
 
 
 566 
 
 
 1,345 
Retirement of Long-term Debt
 
 
 (1,263)
 
 
 (1,341)
Commercial Paper and Credit Facility Repayments
 
 
 (630)
 
 
 (49)
Principal Payments for Capital Lease Obligations
 
 
 (35)
 
 
 (49)
Dividends Paid on Common Stock
 
 
 (446)
 
 
 (399)
Dividends Paid on Cumulative Preferred Stock
 
 
 (1)
 
 
 (1)
Other Financing Activities
 
 
 - 
 
 
 (1)
Net Cash Flows from (Used for) Financing Activities
 
 
 (329)
 
 
 758 
 
 
 
 
 
 
 
Net Increase in Cash and Cash Equivalents
 
 
 123 
 
 
 348 
Cash and Cash Equivalents at Beginning of Period
 
 
 294 
 
 
 490 
Cash and Cash Equivalents at End of Period
 
$
 417 
 
$
 838 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 442 
 
$
 487 
Net Cash Paid for Income Taxes
 
 
 15 
 
 
 174 
Noncash Acquisitions Under Capital Leases
 
 
 28 
 
 
 176 
Government Grants Included in Accounts Receivable at June 30,
 
 
 6 
 
 
 - 
Construction Expenditures Included in Current Liabilities at June 30,
 
 
 292 
 
 
 205 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements.
 
 
 
 
 
 

 
30

 

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

   
1.
Significant Accounting Matters
   
2.
New Accounting Pronouncements
   
3.
Rate Matters
   
4.
Commitments, Guarantees and Contingencies
   
5.
Acquisition and Dispositions
   
6.
Benefit Plans
   
7.
Business Segments
   
8.
Derivatives and Hedging
   
9.
Fair Value Measurements
   
10.
Income Taxes
   
11.
Financing Activities
   
12.
Cost Reduction Initiatives

 
31

 

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 and six months ended June 30, 2011 is not necessarily indicative of results that may be expected for the year ending December 31, 2011.  The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2010 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 25, 2011.

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, the power to direct the VIE and other factors.  We believe that significant assumptions and judgments were applied consistently.

We are the primary beneficiary of Sabine, DCC Fuel, AEP Credit, Transition Funding and a protected cell of EIS.  In addition, we have not provided material financial or other support to Sabine, DCC Fuel, Transition Funding, our protected cell of EIS and AEP Credit that was not previously contractually required.  We hold a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series).

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 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 June 30, 2011 and 2010 were $30 million and $30 million, respectively, and for the six months ended June 30, 2011 and 2010 were $64 million and $73 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on our Condensed Consolidated Balance Sheets.

Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance.  EIS has multiple protected cells.  Neither AEP nor its subsidiaries have an equity investment in 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 expense to the protected cell for the three months ended June 30, 2011 and 2010 was $80 thousand and $254 thousand,
 
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respectively, and for the six months ended June 30, 2011 and 2010 was $30 million and $18 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.

I&M has a nuclear fuel lease agreement with DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC (collectively 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.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC are separate legal entities from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the DCC Fuel LLC and DCC Fuel II LLC leases are made semi-annually and began in April 2010 and October 2010, respectively.  Payments on the DCC Fuel III LLC lease are made monthly and began in January 2011.  Payments on the DCC Fuel leases for the three months ended June 30, 2011 and 2010 were $38 million and $22 million, respectively, and for the six months ended June 30, 2011 and 2010 were $43 million and $22 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the 48, 54 and 54 month lease term, respectively.  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 leases are 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 a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings.  Any third party financing of AEP Credit only has recourse to the receivables securitized 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 “Securitized Accounts Receivable – AEP Credit” section of Note 11.

Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas restructuring law.  Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant.  Therefore, TCC is required to consolidate Transition Funding.  The securitized bonds totaled $1.8 billion and $1.8 billion at June 30, 2011 and December 31, 2010, respectively, and are included in current and long-term debt on the Condensed Consolidated Balance Sheets.  Transition Funding has securitized transition assets of $1.7 billion and $1.7 billion at June 30, 2011 and December 31 2010, respectively, which are presented separately on the face of the Condensed Consolidated Balance Sheets.  The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT.  The securitization bonds are payable only from and secured by the securitized transition assets.  The bondholders have no recourse to TCC or any other AEP entity.  TCC acts as the servicer for Transition Funding’s securitized transition asset and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs.
 
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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
June 30, 2011
(in millions)
 
 
 
   
 
   
 
   
 
   
 
 
SWEPCo
 
I&M
 
Protected Cell
 
 
 
Transition
 
Sabine
 
DCC Fuel
 
of EIS
 
AEP Credit
 
Funding
ASSETS
 
 
   
 
   
 
   
 
   
 
Current Assets
  $ 42     $ 85     $ 125     $ 1,010     $ 197
Net Property, Plant and Equipment
    140       127       -       -       -
Other Noncurrent Assets
    34       80       7       -       1,678
Total Assets
  $ 216     $ 292     $ 132     $ 1,010     $ 1,875
 
                                     
LIABILITIES AND EQUITY
                                     
Current Liabilities
  $ 46     $ 76     $ 39     $ 925     $ 224
Noncurrent Liabilities
    170       216       78       1       1,637
Equity
    -       -       15       84       14
Total Liabilities and Equity
  $ 216     $ 292     $ 132     $ 1,010     $ 1,875

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2010
(in millions)
 
 
 
   
 
   
 
   
 
   
 
 
SWEPCo
 
I&M
 
Protected Cell
 
 
 
Transition
 
Sabine
 
DCC Fuel
 
of EIS
 
AEP Credit
 
Funding
ASSETS
 
 
   
 
   
 
   
 
   
 
Current Assets
  $ 50     $ 92     $ 131     $ 924     $ 214
Net Property, Plant and Equipment
    139       173       -       -       -
Other Noncurrent Assets
    34       112       1       10       1,746
Total Assets
  $ 223     $ 377     $ 132     $ 934     $ 1,960
 
                                     
LIABILITIES AND EQUITY
                                     
Current Liabilities
  $ 33     $ 79     $ 33     $ 886     $ 221
Noncurrent Liabilities
    190       298       85       1       1,725
Equity
    -       -       14       47       14
Total Liabilities and Equity
  $ 223     $ 377     $ 132     $ 934     $ 1,960

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 50% 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.  SWEPCo’s total billings from DHLC for the three months ended June 30, 2011 and 2010 were $15 million and $13 million, respectively, and for the six months ended June 30, 2011 and 2010 were $29 million and $26 million, respectively.  We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC.  Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on our Condensed Consolidated Balance Sheets.
 
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Our investment in DHLC was:

 
June 30, 2011
 
December 31, 2010
 
 
As Reported on
 
 
 
As Reported on
 
 
 
 
the Consolidated
 
Maximum
 
the Consolidated
 
Maximum
 
 
Balance Sheet
 
Exposure
 
Balance Sheet
 
Exposure
 
 
(in millions)
 
Capital Contribution from SWEPCo
  $ 8     $ 8     $ 6     $ 6  
Retained Earnings
    1       1       2       2  
SWEPCo's Guarantee of Debt
    -       54       -       48  
 
                               
Total Investment in DHLC
  $ 9     $ 63     $ 8     $ 56  

We and Allegheny Energy Inc. (AYE) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH).  In February 2011, FirstEnergy Corp. (FirstEnergy) completed its merger with AYE, under which AYE became a wholly-owned subsidiary of FirstEnergy.  Also, in February 2011, PJM directed that work on the PATH project be suspended.  PATH is a series limited liability company and was created to construct a high-voltage transmission line project in the PJM region.  PATH consists of the “West Virginia Series (PATH-WV),” owned equally by AYE and AEP, and the “Allegheny Series” which is 100% owned by AYE.  Provisions exist within the PATH-WV agreement that make it a VIE.  The “Allegheny Series” is not considered a VIE.  We are not required to consolidate PATH-WV as we are not the primary beneficiary, although we hold a significant variable interest in PATH-WV.  Our equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on our Condensed Consolidated Balance Sheets.  We and AYE share the returns and losses equally in PATH-WV.  Our subsidiaries and AYE’s subsidiaries provide services to the PATH companies through service agreements.  As of June 30, 2011, PATH-WV had no debt outstanding.  However, when debt is issued, the debt to equity ratio in each series should be consistent with other regulated utilities.  The entities recover costs through regulated rates.

Given the structure of the entity, we may be required to provide future financial support to PATH-WV in the form of a capital call.  This would be considered an increase to our investment in the entity.  Our maximum exposure to loss is to the extent of our investment.  The likelihood of such a loss is remote since the FERC approved PATH-WV’s request for regulatory recovery of cost and a return on the equity invested.

Our investment in PATH-WV was:

 
June 30, 2011
 
December 31, 2010
 
 
As Reported on
   
 
 
As Reported on
   
 
 
 
the Consolidated
 
Maximum
 
the Consolidated
 
Maximum
 
 
Balance Sheet
 
Exposure
 
Balance Sheet
 
Exposure
 
 
 
 
 
(in millions)
   
 
 
Capital Contribution from AEP
  $ 19     $ 19     $ 18     $ 18  
Retained Earnings
    8       8       6       6  
 
                               
Total Investment in PATH-WV
  $ 27     $ 27     $ 24     $ 24  

Earnings Per Share (EPS)

Basic earnings per common share is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period.  Diluted earnings per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.
 
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The following table presents our basic and diluted EPS calculations included on our Condensed Consolidated Statements of Income:

 
 
Three Months Ended June 30,
 
 
 
2011
   
2010
 
 
 
(in millions, except per share data)
 
 
 
 
 
$/share
   
 
 
$/share
 
Earnings Applicable to AEP Common Shareholders
  $ 352    
 
    $ 136    
 
 
 
         
 
           
 
 
Weighted Average Number of Basic Shares Outstanding
    481.9     $ 0.73       479.1     $ 0.28  
Weighted Average Dilutive Effect of:
                               
Stock Options
    0.1       -       -       -  
Restricted Stock Units
    0.2       -       0.1       -  
Weighted Average Number of Diluted Shares Outstanding
    482.2     $ 0.73       479.2     $ 0.28  

 
 
Six Months Ended June 30,
 
 
 
2011
   
2010
 
 
 
(in millions, except per share data)
 
 
 
 
   
$/share
   
 
   
$/share
 
Earnings Applicable to AEP Common Shareholders
  $ 705    
 
    $ 480    
 
 
 
         
 
           
 
 
Weighted Average Number of Basic Shares Outstanding
    481.5     $ 1.46       478.7     $ 1.00  
Weighted Average Dilutive Effect of:
                               
Performance Share Units
    -       -       0.1       -  
Stock Options
    0.1       -       0.1       -  
Restricted Stock Units
    0.2       -       0.1       -  
Weighted Average Number of Diluted Shares Outstanding
    481.8     $ 1.46       479.0     $ 1.00  

The assumed conversion of stock options does not affect net earnings for purposes of calculating diluted earnings per share.

Options to purchase 70,050 and 432,366 shares of common stock were outstanding at June 30, 2011 and 2010, respectively, but were not included in the computation of diluted earnings per share attributable to AEP common shareholders.  Since the options’ exercise prices were greater than the average market price of the common shares, the effect would have been antidilutive.

2.  NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of final pronouncements, we review the new accounting literature to determine its relevance, if any, to our business.  The following represents a summary of final pronouncements that impact our financial statements.

Pronouncements Issued During 2011

The following standard was issued during the first six months of 2011.  The following paragraphs discuss its impact on future financial statements.

ASU 2011-05 “Presentation of Comprehensive Income” (ASU 2011-05)

In June 2011, the FASB issued ASU 2011-05 eliminating the option to present the components of other comprehensive income as a part of the statement of shareholders’ equity.  The standard requires other comprehensive income be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income.  Reclassification adjustments from other comprehensive income to net income must be presented on the face of the financial statements.  This standard must be retrospectively applied to all reporting periods presented in financial reports issued after the effective date.
 
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The new accounting guidance is effective for interim and annual periods beginning after December 15, 2011.  This standard will change the presentation of our financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. We will adopt ASU 2011-05 effective January 1, 2012.

3.  RATE MATTERS

As discussed in the 2010 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within our 2010 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition.  The following discusses ratemaking developments in 2011 and updates the 2010 Annual Report.

Regulatory Assets Not Yet Being Recovered
 
 
   
 
 
 
 
June 30,
   
December 31,
 
 
 
2011
   
2010
 
 
 
(in millions)
 
Noncurrent Regulatory Assets (excluding fuel)
 
 
   
 
 
Regulatory assets not yet being recovered pending future proceedings
 
 
   
 
 
 to determine the recovery method and timing:
 
 
   
 
 
Regulatory Assets Currently Earning a Return
 
 
   
 
 
Line Extension Carrying Costs - CSPCo, OPCo (a)
  $ 61     $ 55  
Customer Choice Deferrals - CSPCo, OPCo (a)
    60       59  
Storm Related Costs - CSPCo, OPCo (a)
    31       30  
Storm Related Costs - TCC
    25       25  
Storm Related Costs - PSO (c)
    18       -  
Acquisition of Monongahela Power - CSPCo (a)
    9       8  
Other Regulatory Assets Not Yet Being Recovered
    7       7  
Regulatory Assets Currently Not Earning a Return
               
Environmental Rate Adjustment Clause - APCo
    65       56  
Storm Related Costs - APCo, KGPCo, SWEPCo
    28       28  
Deferred Wind Power Costs - APCo
    38       29  
Mountaineer Carbon Capture and Storage Product Validation Facility - APCo (b)
    19       60  
Special Rate Mechanism for Century Aluminum - APCo
    13       13  
Acquisition of Monongahela Power - CSPCo (a)
    4       4  
Storm Related Costs - PSO (c)      -        17  
Other Regulatory Assets Not Yet Being Recovered
    5       4  
Total Regulatory Assets Not Yet Being Recovered
  $ 383     $ 395  

(a)
Requested to be recovered in a distribution asset recovery rider.  See the "2011 Ohio Distribution Base Rate Case" section below.
(b)
APCo wrote off a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC in March 2011.  See "Mountaineer Carbon Capture and Storage Project Product Validation Facility" section below.
(c)
In June 2011, an order was received approving recovery of PSO storm costs and associated carrying costs with recovery to begin in August 2011.  Starting in the second quarter of 2011, and in accordance with the order received from the OCC, PSO recorded a return on its storm related costs.

CSPCo and OPCo Rate Matters

Ohio Electric Security Plan Filings

2009 – 2011 ESPs

The PUCO issued an order in March 2009 that modified and approved CSPCo’s and OPCo’s ESPs which established rates at the start of the April 2009 billing cycle.  The ESPs are in effect through 2011.  The order also limited annual 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.  Some rate components and increases are exempt from these limitations.  CSPCo and OPCo collected the 2009 annualized revenue increase over the last nine months of 2009.
 
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The order provided a FAC for the three-year period of the ESP.  The FAC was phased in to avoid having the resultant rate increases exceed the ordered annual caps described above.  The FAC is subject to quarterly true-ups, annual accounting audits and prudency reviews.  See the “2009 Fuel Adjustment Clause Audit” section below.  The order allowed CSPCo and OPCo to defer any unrecovered FAC costs resulting from the annual caps and to accrue associated carrying charges at their respective weighted average cost of capital.  Any deferred FAC regulatory asset balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018.  That recovery will include deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges.  See the “Ormet Interim Arrangement” section below.  The FAC deferral as of June 30, 2011 was $27 million and $526 million for CSPCo and OPCo, respectively, excluding $388 thousand and $43 million, respectively, of unrecognized equity carrying costs.

Discussed below are the significant outstanding uncertainties related to the ESP order:

The Ohio Consumers’ Counsel filed a notice of appeal with the Supreme Court of Ohio raising several issues including alleged retroactive ratemaking, recovery of carrying charges on certain environmental investments, Provider of Last Resort (POLR) charges and the decision not to offset rates by off-system sales margins.  In November 2009, the Industrial Energy Users-Ohio (IEU) filed a notice of appeal with the Supreme Court of Ohio challenging components of the ESP order including the POLR charge, the distribution riders for gridSMART® and enhanced reliability, the PUCO’s conclusion and supporting evaluation that the modified ESPs are more favorable than the expected results of a market rate offer, the unbundling of the fuel and non-fuel generation rate components, the scope and design of the fuel adjustment clause and the approval of the plan after the 150-day statutory deadline.

In April 2011, the Supreme Court of Ohio (the Court) issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact through a remand proceeding.  First, the Court concluded that the PUCO's decision amounted to retroactive ratemaking.  Since the pertinent revenues were collected in 2009 and the Ohio Consumers’ Counsel did not successfully pursue the remedy of obtaining a stay of the order prior to the revenues being collected, there is no remand to the PUCO or refund to customers for this error.  Second, the Court held that the PUCO's conclusion that the POLR charge is cost-based conflicted with the evidence and remanded the issue to the PUCO for further consideration.  Third, the Court reversed the order’s legal basis for a carrying charge associated with certain environmental investments and remanded that issue to the PUCO to determine whether an alternative legal basis supports the charge.  Pursuant to a May 2011 PUCO order, CSPCo and OPCo implemented rates subject to refund and filed remand testimony in June 2011.  For the month ended June 30, 2011, CSPCo and OPCo recorded $14 million and $16 million, respectively, of revenues subject to refund.  In June 2011, the Ohio Consumers’ Counsel and the IEU filed testimony recommending a complete denial of collection of any POLR charges and carrying charges on certain environmental investments collected from 2009 through 2011.  They proposed unfavorable adjustments for CSPCo and OPCo of up to $370 million and $417 million, respectively, excluding carrying costs.  The proposed adjustments include a reduction of deferred FAC and other regulatory assets for the period prior to June 2011 of up to $298 million and $336 million for CSPCo and OPCo, respectively, which management believes is without merit and violates the Court’s decision.  The proposed adjustments also include refunds and rate reductions of related revenues beginning in June 2011 of $72 million and $81 million for CSPCo and OPCo, respectively.  Hearings were held in July 2011.

In April 2010, the IEU filed an additional notice of appeal with the Court challenging alleged retroactive ratemaking, CSPCo and OPCo's abilities to collect through the FAC amounts deferred under the Ormet interim arrangement and the approval of the plan after the 150-day statutory deadline.  In June 2011, the Court affirmed the PUCO’s decision and dismissed the IEU’s appeal.

In January 2011, the PUCO issued an order on CSPCo’s and OPCo’s 2009 SEET filings and determined that OPCo’s 2009 earnings were not significantly excessive but determined relevant CSPCo earnings exceeded the PUCO determined threshold by 2.13%.  As a result, the PUCO ordered CSPCo to refund $43 million ($28 million net of tax) of its earnings to customers, which was recorded as a revenue provision on CSPCo’s December 2010 books.  The PUCO ordered that the significantly excessive earnings be applied first to CSPCo’s FAC deferral, including unrecognized equity carrying costs, as of the date of the order, with any remaining
 
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balance to be credited to CSPCo’s customers on a per kilowatt basis.  That credit began with the first billing cycle in February 2011 and will continue through December 2011.  Several parties, including CSPCo and OPCo, filed requests for rehearing with the PUCO, which were denied in March 2011.  In May 2011, the IEU and the Ohio Energy Group filed appeals with the Court challenging the PUCO’s SEET decisions.  CSPCo and OPCo are required to file their 2010 SEET filings with the PUCO in 2011.  Based upon the approach in the PUCO 2009 order, management does not currently believe that CSPCo or OPCo had any significantly excessive earnings in 2010.

Management is unable to predict the outcome of the ESP remand proceeding and litigation discussed above.  If these proceedings, including future SEET filings, result in adverse rulings, it could reduce future net income and cash flows and impact financial condition.

January 2012 – May 2014 ESP

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing on a combined company basis for generation.  The rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The ESP also includes alternative energy resource requirements and addresses provisions regarding distribution service, energy efficiency requirements, economic development, job retention in Ohio, generation resources and other matters.  The SSO presents redesigned generation rates by customer class.  Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013.  The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESP could impact the outcome of the January 2012-May 2014 ESP, though the nature and extent of that impact is not presently known.  In July 2011, various intervenors filed testimony that generally asserts CSPCo's and OPCo's proposed SSO rates are higher than the market-rate offer, and objects to certain proposed riders as well as to the proposed non-bypassable nature of certain riders.  Additionally, the IEU and Ohio Consumers' Counsel object to revenues collected in the period 2009 through 2011 for POLR and carrying charges related to environmental investments and propose similar adjustments as discussed in the ESP remand proceeding.  See the "2009-2011 ESPs" section above.  A hearing for this case is scheduled for August 2011 and a decision is expected in the fourth quarter of 2011.

2011 Ohio Distribution Base Rate Case

In February 2011, CSPCo and OPCo filed with the PUCO for annual increases in distribution rates of $34 million and $60 million, respectively.  The requested increase is based upon an 11.15% return on common equity to be effective January 2012.

In addition to the annual increases, CSPCo and OPCo requested recovery of the projected December 31, 2012 balances of certain distribution regulatory assets of $216 million and $159 million, respectively, including approximately $102 million and $84 million, respectively, of unrecognized equity carrying costs.  These assets and unrecognized carrying costs would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013.  The actual balance of these distribution regulatory assets as of June 30, 2011 was $100 million and $64 million for CSPCo and OPCo, respectively, excluding $61 million and $45 million, respectively, of unrecognized equity carrying costs.  If CSPCo and OPCo are not ultimately permitted to fully recover their deferrals, it would reduce future net income and cash flows and impact financial condition.

Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo.  Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company.  In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo.  CSPCo and OPCo requested the reorganization transaction be effective in October 2011.  In July 2011, the FERC issued an order approving the proposed merger.  A decision is pending from the PUCO.  Management is unable to predict the outcome of this proceeding.
 
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Requested Sporn Unit 5 Shutdown and Proposed Distribution Rider

In October 2010, OPCo filed an application with the PUCO for the approval of a December 2010 closure of Sporn Unit 5 and the simultaneous establishment of a new non-bypassable distribution rider outside the rate caps established in the 2009 – 2011 ESP proceeding.  The proposed rider would recover the net book value of the unit as well as related materials and supplies as of December 2010, which was estimated to total $59 million, as well as future closure costs incurred after December 2010.  OPCo also requested authority to record the future closure costs as a regulatory asset or regulatory liability with a weighted average cost of capital carrying charge to be included in the proposed non-bypassable distribution rider after the costs are incurred.  Pending PUCO approval, Sporn Unit 5 continues to operate.  In April 2011, intervenors filed comments opposing OPCo’s application.  A PUCO decision is pending as to whether a hearing will be ordered.  Management is unable to predict the outcome of this proceeding.

2009 Fuel Adjustment Clause Audit

As required under the ESP orders, the PUCO selected an outside consultant to conduct the audit of the FAC for CSPCo and OPCo for the period of January 2009 through December 2009.  In May 2010, the outside consultant provided its confidential audit report to the PUCO.  The audit report included a recommendation that the PUCO review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo’s FAC under-recovery balance.  Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009 and $14 million was recognized as a reduction to fuel expense in 2009 and 2010.  Hearings were held in August 2010.  A decision from the PUCO is pending.  Management is unable to predict the outcome of this proceeding.  If the PUCO orders any portion of the $58 million previously recognized gains or any future adjustments be used to reduce the FAC deferral, it would reduce future net income and cash flows and impact financial condition.

2010 Fuel Adjustment Clause Audit

In May 2011, the PUCO-selected outside consultant issued their results of the 2010 FAC audit for CSPCo and OPCo.  The audit report included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balances and determine whether the carrying costs on the balances should be net of accumulated income taxes.  As of June 30, 2011, the amount of OPCo’s carrying costs that could potentially be at risk is estimated to be $13 million, excluding $16 million of unrecognized equity carrying costs. The amount of carrying costs for CSPCo that could potentially be at risk is immaterial.  A decision from the PUCO is pending.  Management is unable to predict the outcome of this proceeding.  If the PUCO order results in a reduction in the carrying charges related to the FAC deferrals, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

CSPCo, OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet.  This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009.  In March 2009, the PUCO approved a FAC in the ESP filings and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio’s April 2011 decision referenced in the “2009-2011 ESPs” section above.  The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record regulatory assets for the difference between the approved market price and the rate paid by Ormet.  Through September 2009, the last month of the interim arrangement, CSPCo and OPCo had $30 million and $34 million, respectively, of deferred FAC related to the interim arrangement including recognized carrying charges.  These amounts exclude $1 million and $1 million, respectively, of unrecognized equity carrying costs.  In November 2009, CSPCo and OPCo requested that the PUCO approve recovery of the deferrals under the interim agreement plus a weighted average cost of capital carrying charge.  The interim arrangement deferrals are included in CSPCo’s and OPCo’s FAC phase-in deferral balances.  See “Ohio Electric Security Plan Filings” section above.  In the ESP proceeding, intervenors requested that CSPCo and OPCo be required to refund the Ormet-related regulatory assets and requested that the PUCO prevent CSPCo and OPCo from collecting the Ormet-related revenues in the future.  The PUCO did not take any action on this request in the 2009-2011 ESP proceeding.  The intervenors raised the issue again in response to CSPCo’s and OPCo’s November 2009 filing to approve recovery of the deferrals under the interim agreement and this issue remains pending before the PUCO.  If CSPCo and OPCo are not ultimately permitted to fully recover their requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.
 
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Economic Development Rider

In April 2010, the IEU filed a notice of appeal of the 2009 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio.  The EDR collects from ratepayers the difference between the standard tariff and lower contract billings to qualifying industrial customers, subject to PUCO approval.  The IEU raised several issues including claims that: (a) the PUCO lost jurisdiction over CSPCo’s and OPCo’s ESP proceedings and related proceedings when the PUCO failed to issue ESP orders within the 150-day statutory deadline, (b) the EDR should not be exempt from the ESP annual rate limitations and (c) CSPCo and OPCo should not be allowed to apply a weighted average long-term debt carrying cost on deferred EDR regulatory assets.  In June 2011, the Supreme Court of Ohio affirmed the PUCO’s decision and dismissed the IEU’s appeal.

In June 2010, the IEU filed a notice of appeal of the 2010 PUCO-approved EDR with the Supreme Court of Ohio raising the same issues as noted in the 2009 EDR appeal.  In addition, the IEU added a claim that CSPCo and OPCo should not be able to take the benefits of the higher ESP rates while simultaneously challenging the ESP orders.  In June 2011, the IEU voluntarily dismissed the 2010 EDR appeal issues that were the same issues dismissed by the Supreme Court of Ohio in their 2009 EDR appeal referenced above.  A decision from the Supreme Court of Ohio is pending on the remaining issue.

As of June 30, 2011, CSPCo and OPCo have incurred EDR costs of $59 million and $55 million, respectively, including carrying costs.  Of these costs, CSPCo and OPCo have collected $50 million and $39 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010.  The remaining $9 million and $16 million for CSPCo and OPCo, respectively, are recorded as deferred EDR regulatory assets.  If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund EDR revenue collected, it would reduce future net income and cash flows and impact financial condition.

Ohio IGCC Plant

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  Through June 30, 2011, CSPCo and OPCo have collected $12 million and $12 million, respectively, in pre-construction costs authorized in a June 2006 PUCO order and incurred $11 million and $11 million, respectively, in pre-construction costs.  As a result, CSPCo and OPCo established net regulatory liabilities of approximately $1 million and $1 million, respectively.  The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant before June 2011, any pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest.  As of June 2011, there were no active IGCC projects at other AEP sites.  In June 2011, CSPCo and OPCo filed a recommendation with the PUCO to refund to customers $2 million and $2 million, respectively, for the over-recovered pre-construction costs including interest.  Intervenors have filed motions with the PUCO requesting all collected pre-construction costs be refunded to Ohio ratepayers with interest.

Management cannot predict the outcome of any cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, such litigation would have on future net income and cash flows.  However, if CSPCo and OPCo are required to refund pre-construction costs collected in excess of the over-recovered pre-construction costs, it would reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

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% (440 MW) of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $124 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $124 million for transmission, excluding AFUDC.  As of June 30, 2011, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $1.2 billion of expenditures (including AFUDC and capitalized interest of $175 million and related transmission costs of $79 million).  As of June 30, 2011, the joint owners and SWEPCo have contractual
 
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construction commitments of approximately $211 million (including related transmission costs of $11 million).  SWEPCo’s share of the contractual construction commitments is $157 million.  If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of June 30, 2011, of approximately $101 million (including related transmission cancellation fees of $1 million).  SWEPCo’s share of the contractual construction cancellation fees would be approximately $74 million.

Discussed below are the significant outstanding uncertainties related to the Turk Plant:

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the 88 MW SWEPCo Arkansas jurisdictional share of the Turk Plant.  Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN.  The Arkansas Supreme Court ultimately concluded that the APSC erred in determining the need for additional power supply resources in a proceeding separate from the proceeding in which the APSC granted the CECPN.  However, the Arkansas Supreme Court approved the APSC’s procedure of granting CECPNs for transmission facilities in dockets separate from the Turk Plant CECPN proceeding.  SWEPCo filed a notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates.  In June 2010, the APSC issued an order which reversed and set aside the previously granted CECPN.

The PUCT issued an order approving a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers.  SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful.  The Texas Industrial Energy Consumers filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because it was unnecessary to serve retail customers.  In February 2010, the Texas District Court affirmed the PUCT’s order in all respects.  In March 2010, SWEPCo and the Texas Industrial Energy Consumers appealed this decision to the Texas Court of Appeals.  Management is unable to predict the timing of the outcome related to this proceeding.

In November 2008, SWEPCo received its required air permit approval from the Arkansas Department of Environmental Quality and commenced construction at the site.  The Arkansas Pollution Control and Ecology Commission (APCEC) upheld the air permit.  The parties who unsuccessfully appealed the air permit to the APCEC filed a notice of appeal with the Circuit Court of Hempstead County, Arkansas.  In December 2010, the Circuit Court affirmed the APCEC.  In January 2011, the same parties filed a notice of appeal with the Arkansas Court of Appeals.  A decision is likely in the second half of 2011.

A wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009.  In 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts, and sought a preliminary injunction to halt construction and for a temporary restraining order.  In July 2010, the Hempstead County Hunting Club (Hunting Club) also filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of the Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws.  The plaintiffs’ federal law claims challenge the process used and terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts.  The plaintiffs’ state law claims challenge SWEPCo's ability to construct the Turk Plant without obtaining a certificate from the APSC.  In October 2010, the Federal District Court certified issues relating to the state law claims to the Arkansas Supreme Court, including whether those claims are within the primary jurisdiction of the APSC.  In May 2011, the Arkansas Supreme Court determined that these claims must first be brought before the APSC and that the federal court does not have jurisdiction to hear the state law claims.  In 2010, the motions for preliminary injunction were partially granted.  According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop.  Mitigation measures required by the permit are authorized and may be completed.  The preliminary injunction
 
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affects portions of the water intake and portions of two transmission lines.  SWEPCo appealed the issuance of the preliminary injunction to the U.S. Eighth Circuit Court of Appeals, and in July 2011, the Court of Appeals affirmed the preliminary injunction.  Management is unable to predict the timing or the outcome related to this remand proceeding.

In July 2011, SWEPCo reached an agreement in principle that would resolve all pending matters between SWEPCo, the Hunting Club and several other parties.  As a result, the Hunting Club’s challenge to the U.S. Army Corps of Engineers permit in the Federal District Court for the Western District of Arkansas will be dismissed and the Hunting Club’s appeal of the air permit will be withdrawn.  Additional judicial and administrative proceedings will also be terminated.  SWEPCo was unable to resolve claims by the Sierra Club and the Audubon Society, so their challenges to the wetlands and air permits will continue.

Management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service.  However, if SWEPCo is unable to complete the Turk Plant construction, including the related transmission facilities, and place the Turk Plant in service or if SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.

TCC Rate Matters

TEXAS RESTRUCTURING

Texas Restructuring Appeals

Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020.  TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders.  TCC and intervenors appealed the PUCT’s true-up related orders.  After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Supreme Court of Texas.  In July 2011, the Supreme Court of Texas granted review and issued its opinion.  The following issues were decided by the Supreme Court:

·  
The PUCT’s order denying recovery of capacity auction true-up amounts was reversed.  We estimate that, in the remand to the PUCT, TCC will be entitled to recover approximately $420 million, plus interest from January 1, 2002.

·  
The Supreme Court of Texas reversed the Texas Court of Appeals decision and found that the PUCT could adjust the net book value for what it determined to be commercially unreasonable conduct.  This portion of the decision is unfavorable, but was already reflected in our financial statements.

·  
The Supreme Court of Texas affirmed the PUCT’s finding that the sales price should be used to value TCC’s nuclear generation.  This portion of the decision is favorable, but this issue will have no impact on TCC’s rate recovery as this was already reflected in our financial statements.

·  
The Supreme Court of Texas reversed the Court of Appeal’s decision and found it was appropriate for the PUCT to take into account previously refunded excess mitigation credits to affiliate retail electricity providers.  This portion of the decision upheld the PUCT’s decision.  However, resolution of related issues will be addressed on remand.

·  
The PUCT decisions allowing recovery of construction work in progress balances and specifying the interest rate on stranded costs were upheld.  These decisions are already reflected in our financial statements and will not be addressed in the remand proceeding.

No parties have filed for rehearing with the Supreme Court of Texas, and the case will be remanded to the PUCT.
 
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TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

In 2006, the PUCT reduced recovery of the amount securitized by $103 million of tax benefits and associated carrying costs related to TCC’s generation assets.  In 2006, TCC obtained a private letter ruling from the IRS which confirmed that such a reduction was an IRS normalization violation.  In order to avoid a normalization violation, the PUCT agreed to allow TCC to defer refunding the tax benefits of $103 million plus interest through the CTC refund period pending resolution of the normalization issue.  In 2008, the IRS issued final regulations, which supported the IRS’s private letter ruling which would make the refunding of or the reduction of the amount securitized by such tax benefits a normalization violation.  After the IRS issued its final regulations the Texas Court of Appeals, at the request of the PUCT, remanded the tax normalization issue to the PUCT for the consideration of additional evidence including the IRS regulations.  The issue will be considered by the PUCT when the true-up proceeding is remanded following the July 2011 Supreme Court of Texas decision.  See the “Texas Restructuring Appeals” section above.  TCC is not accruing interest on the $103 million because management believes it is not probable that the PUCT will order TCC to violate the normalization provision of the Internal Revenue Code.  If interest were accrued, management estimates interest expense would have been approximately $27 million higher for the period July 2008 through June 2011.

Management believes that the PUCT will ultimately allow TCC to retain the deferred amounts, which would have a favorable effect on future net income and cash flows.  Although unexpected, if the PUCT fails to issue a favorable order and orders TCC to return the tax benefits to customers, the resulting normalization violation could result in TCC’s repayment to the IRS of Accumulated Deferred Investment Tax Credits (ADITC) on all property, including transmission and distribution property.  This amount approximates $101 million as of June 30, 2011.  It could also lead to a loss of TCC’s right to claim accelerated tax depreciation in future tax returns.  If TCC is required to repay its ADITC to the IRS and is also required to refund ADITC plus unaccrued interest to customers, it would reduce future net income and cash flows and impact financial condition.

TCC Excess Earnings

In 2005, a Texas appellate court issued a decision finding that a PUCT order requiring TCC to refund to the REPs excess earnings prior to and outside of the true-up process was unlawful under the Texas Restructuring Legislation.  From 2002 to 2005, TCC refunded $55 million of excess earnings, including interest, under the overturned PUCT order.  The PUCT must determine if adjustments are required on remand based on the July 2011 decision of the Supreme Court of Texas on the impact of excess earnings in the true-up proceeding.  See the “Texas Restructuring Appeals” section above.

APCo and WPCo Rate Matters

2011 Virginia Biennial Base Rate Case

In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012.  The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law. APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing.  If approved, APCo’s net base rate increase would be $75 million.  In July 2011, an Attorney General witness recommended an $80 million reduction in APCo’s requested rate year capacity charges.

Rate Adjustment Clauses

In 2007, the Virginia law governing the regulation of electric utility service was amended to, among other items, provide for rate adjustment clauses (RACs) beginning in January 2009 for the timely and current recovery of costs of: (a) transmission services billed by an RTO, (b) demand side management and energy efficiency programs, (c) renewable energy programs, (d) environmental compliance projects and (e) new generation facilities, including major unit modifications.  In March 2011, APCo filed for approval of an environmental RAC, a renewable energy program RAC and a generation RAC simultaneous with the 2011 Virginia base rate filing.  The environmental RAC is requesting recovery of environmental compliance costs incurred from January 2009 through December 2010 of $38 million annually based on a two-year amortization.  The renewable energy program RAC is requesting the
 
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incremental portion of deferred wind power costs for the Camp Grove and Fowler Ridge projects of $6 million.  The generation RAC is requesting recovery of the Dresden Plant, currently under construction, which APCo has requested to purchase from AEGCo.      

In accordance with Virginia law, APCo is deferring incremental environmental costs incurred after December 2008 and renewable energy costs incurred after August 2009 which are not being recovered in current revenues.  As of June 30, 2011, APCo has deferred $65 million of environmental costs (excluding $15 million of unrecognized equity carrying costs) and $38 million of renewable energy costs.  APCo plans to seek recovery of non-incremental deferred wind power costs ($32 million as of June 30, 2011) in future rate proceedings.  If the Virginia SCC were to disallow a portion of APCo’s deferred costs, it would reduce future net income and cash flows.

2010 West Virginia Base Rate Case

In May 2010, APCo and WPCo filed a request with the WVPSC to increase annual base rates by $156 million based on an 11.75% return on common equity to be effective March 2011.  In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $51 million based upon a 10% return on common equity.  The settlement agreement also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011.  See “Mountaineer Carbon Capture and Storage Project” section below.  In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and allowed APCo and WPCo to defer and amortize $15 million of previously expensed costs related to the 2010 cost reduction initiatives, each over a period of seven years.

Mountaineer Carbon Capture and Storage Project

Product Validation Facility (PVF)

APCo and ALSTOM Power, Inc., 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 October 2009, APCo started injecting CO2 into the underground storage facilities.  The injection of CO2 required the recording of an asset retirement obligation and an offsetting regulatory asset.  In May 2011, the PVF ended operations and decommissioning of the facility began.

In APCo’s and WPCo’s May 2010 West Virginia base rate filing, APCo and WPCo requested rate base treatment of the PVF, including recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In March 2011, a WVPSC order denied the request for rate base treatment of the PVF largely due to its experimental operation.  The base rate order provided that should APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the PVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base.  As a result, APCo recorded a pretax write-off of $41 million ($26 million net of tax) in the first quarter of 2011 recorded to Other Operation expense on the Condensed Consolidated Statements of Operations.  See “2010 West Virginia Base Rate Case” section above.  As of June 30, 2011, APCo has recorded a noncurrent regulatory asset of $19 million related to the PVF.  If APCo cannot recover its remaining PVF investment and related accretion expenses, it would reduce future net income and cash flows.

Carbon Capture and Sequestration Project with the Department of Energy (DOE) (Commercial Scale Project)

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility at the Mountaineer Plant.  AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project.  The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million.  In July 2011, management informed the DOE that it will complete a Front-End Engineering and Design study during the third quarter of 2011, but it is postponing any further CCS project activities because of the uncertainty about the regulation of CO2.  As of June 30, 2011, the project has incurred $30 million in total costs and has received $10 million of DOE eligible funding resulting in a $20 million net balance recorded in Deferred Charges and Other Noncurrent Assets on the Condensed Consolidated Balance Sheets.  Requests for recovery are in process in Michigan, Ohio and Virginia.  If the costs of the CCS project cannot be recovered, it would reduce future net income and cash flows.
 
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APCo’s Filings for an IGCC Plant

In 2008, the Virginia SCC issued an order denying APCo’s request for a surcharge rate mechanism to provide for the timely recovery of pre-construction costs and the ongoing financing costs of the project during the construction period, as well as the capital costs, operating costs and a return on common equity once the facility is placed into commercial operation.  The order was based upon the Virginia SCC's finding that the estimated cost of the plant was uncertain and may escalate.  The Virginia SCC also expressed concerns that the estimated costs did not include a retrofitting of CCS facilities.  During 2009, based on the order received in Virginia, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional Certificate of Environmental Compatibility and Public Need granted in 2008 must be reconsidered if and when APCo proceeds with the IGCC plant.

Through June 30, 2011, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction.

APCo will not start construction of the IGCC plant until sufficient assurance of full cost recovery exists in Virginia and West Virginia.  If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs.  If the costs are not recoverable, it would reduce future net income and cash flows and impact financial condition.

APCo’s and WPCo’s Expanded Net Energy Charge (ENEC) Filing

In September 2009, the WVPSC issued an order approving APCo’s and WPCo’s March 2009 ENEC request.  The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $355 million and a first-year increase of $124 million, effective October 2009.

In June 2010, the WVPSC approved a settlement agreement for $96 million, including $10 million of construction surcharges related to APCo’s and WPCo’s second year ENEC increase.  The settlement agreement allows APCo to accrue a weighted average cost of a capital carrying charge on the excess under-recovery balance due to the ENEC phase-in as adjusted for the impacts of Accumulated Deferred Income Taxes.  The new rates became effective in July 2010.

In June 2011, the WVPSC issued an order approving a $98 million annual increase including $8 million of construction surcharges and $8 million of carrying charges related to APCo’s and WPCo’s third year ENEC increase.  The order also allows APCo to accrue a fixed annual carrying cost rate of 4%.  The new rates became effective in July 2011.  Additionally, the order approved APCo’s request to purchase the Dresden Plant, currently under construction, from AEGCo and approved deferral of post in-service Dresden Plant costs, including a return, for future recovery.  As of June 30, 2011, APCo’s ENEC under-recovery balance was $387 million, excluding $8 million of unrecognized equity carrying costs, which is included in noncurrent regulatory assets.  If the WVPSC were to disallow a portion of APCo’s and WPCo’s deferred ENEC costs, it could reduce future net income and cash flows and impact financial condition.

PSO Rate Matters

PSO 2008 Fuel and Purchased Power

In July 2009, the OCC initiated a proceeding to review PSO’s fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudency review of the related costs.  In March 2010, the Oklahoma Attorney General and the Oklahoma Industrial Energy Consumers (OIEC) recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of off-system sales margins decrease from 25% to 10%.  The OIEC also recommended that the OCC conduct a comprehensive review of all affiliate fuel transactions during 2007 and 2008.  In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEPEP was filed.  The testimony included unquantified refund recommendations relating to re-pricing of those ERCOT trading contracts.  Hearings were held in June 2011.  If the OCC were to issue an unfavorable decision, it could reduce future net income and cash flows and impact financial condition.
 
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I&M Rate Matters

Michigan 2009 and 2010 Power Supply Cost Recovery (PSCR) Reconciliations (Cook Plant Unit 1 Fire and Shutdown)

In March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC.  The filing included an adjustment to exclude from the PSCR the incremental fuel cost of replacement power due to the Unit 1 outage from mid-December 2008 through December 2009, the period during which I&M received and recognized accidental outage insurance proceeds.  In October 2010, a settlement agreement was filed with the MPSC which included deferring the Unit 1 outage issue to the 2010 PSCR reconciliation.  In March 2011, I&M filed its 2010 PSCR reconciliation with the MPSC.  If any fuel clause revenues or accidental outage insurance proceeds have to be paid to customers, it would reduce future net income and cash flows and impact financial condition.  See the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

2011 Michigan Base Rate Case

In July 2011, I&M filed a request with the MPSC for an annual increase in Michigan base rates of $25 million and a return on equity of 11.15%.  The request includes an increase in depreciation rates that would result in a $6 million increase in depreciation expense.

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund

In 2004, AEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA, to partially mitigate the loss of T&O revenues on a temporary basis through March 2006.  Intervenors objected to the temporary SECA rates.  The FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund.  The AEP East companies recognized gross SECA revenues of $220 million from 2004 through 2006 when the SECA rates terminated.

In 2006, a FERC Administrative Law Judge (ALJ) issued an initial decision finding that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.  The ALJ also found that any unpaid SECA rates must be paid in the recommended reduced amount.

AEP filed briefs jointly with other affected companies asking the FERC to reverse the decision.  In May 2010, the FERC issued an order that generally supports AEP’s position and required a compliance filing to be filed with the FERC by August 2010.  In June 2010, AEP and other affected companies filed a joint request for rehearing with the FERC.

In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC.  If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million.  The AEP East companies could also potentially receive payments up to approximately $10 million including estimated interest of $3 million.  A decision is pending from the FERC.

The FERC has approved settlements applicable to $112 million of SECA revenue.  The AEP East companies provided reserves for net refunds for SECA settlements applicable to the remaining $108 million of SECA revenues collected.  Based on the AEP East companies’ analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the May 2010 order or the compliance filing be made final.  Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.
 
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Possible Termination of the Interconnection Agreement

In December 2010, each of the AEP Power Pool members gave notice to AEPSC and each other of their decision to terminate the Interconnection Agreement effective January 2014 or such other date approved by FERC, subject to state regulatory input.  No filings have been made at the FERC.  It is unknown at this time whether the AEP Power Pool will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.  This decision to terminate is subject to management’s ongoing evaluation.  The AEP Power Pool members may revoke their notices of termination.  If any of the AEP Power Pool members experience decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

PJM/MISO Market Flow Calculation Settlement Adjustments

During 2009, an analysis conducted by MISO and PJM discovered several instances of unaccounted for power flows on numerous coordinated flowgates.  These flows affected the settlement data for congestion revenues and expenses and dated back to the start of the MISO market in 2005.  In January 2011, PJM and MISO reached a settlement agreement where the parties agreed to net various issues to zero.  In June 2011, the FERC approved the settlement agreement.

4.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

We are subject to certain claims and legal actions arising in our ordinary course of business.  In addition, our business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation against us cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on our financial statements.  The Commitments, Guarantees and Contingencies note within our 2010 Annual Report should be read in conjunction with this report.

GUARANTEES

We record liabilities for guarantees in accordance with the accounting guidance for “Guarantees.”  There is no collateral held in relation to any guarantees in excess of our ownership percentages.  In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters of Credit

We enter into standby letters of credit with third parties.  As Parent, we issue all of these letters of credit in our ordinary course of business on behalf of our subsidiaries.  These letters of credit cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

We have two $1.5 billion credit facilities, under which we may issue up to $1.35 billion as letters of credit.  In July 2011, we replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015.  As of June 30, 2011, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $132 million with maturities ranging from September 2011 to April 2012.

In March 2011, we terminated a $478 million credit agreement that was scheduled to mature in April 2011 and was used to support $472 million of variable rate Pollution Control Bonds.  In March 2011, we remarketed $357 million of variable rate Pollution Control Bonds using bilateral letters of credit for $361 million to support the remarketed Pollution Control Bonds.  The remaining $115 million of Pollution Control Bonds were reacquired and are held by trustees.
 
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Guarantees of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of approximately $65 million.  In July 2011, SWEPCo’s guarantee was increased to $100 million due to expansion of the mining area.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), a consolidated variable interest entity.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  As of June 30, 2011, SWEPCo has collected approximately $51 million through a rider for final mine closure and reclamation costs, of which $1 million is recorded in Other Current Liabilities, $30 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $20 million is recorded in Asset Retirement Obligations on our Condensed Consolidated Balance Sheets.

Sabine charges SWEPCo, its only customer, all of its costs.  SWEPCo passes these costs to customers through its fuel clause.

Indemnifications and Other Guarantees

Contracts

We enter into several types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, our exposure generally does not exceed the sale price.  The status of certain sale agreements is discussed in the 2010 Annual Report “Dispositions” section of Note 7.  As of June 30, 2011, there were no material liabilities recorded for any indemnifications.

Master Lease Agreements

We lease certain equipment under master lease agreements.  In December 2010, we signed a new master lease agreement with GE Capital Commercial Inc. (GE) for approximately $137 million to replace existing operating and capital leases with GE.  We refinanced $60 million of capital leases and $77 million of operating leases.  These assets were included in existing master lease agreements that were to be terminated in 2011 since GE exercised the termination provision related to these leases in 2008.  In January 2011, we purchased $5 million of previously leased assets that were not included in the 2010 refinancing.  In June 2011, we placed an additional $11 million of previously leased assets under a new capital lease.

For equipment under the GE master lease agreements, the lessor is guaranteed receipt of up to 78% of the unamortized balance of the equipment at the end of the lease term.  If the fair value of the leased equipment is below the unamortized balance at the end of the lease term, we are committed to pay the difference between the fair value and the unamortized balance, with the total guarantee not to exceed 78% of the unamortized balance.  For equipment under other master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, we are committed to pay the difference between the actual fair value and the residual value guarantee.  At June 30, 2011, the maximum potential loss for these lease agreements was approximately $15 million assuming the fair value of the equipment is zero at the end of the lease term.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.
 
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Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignments are accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $16 million for I&M and $18 million for SWEPCo for the remaining railcars as of June 30, 2011.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 84% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  I&M’s maximum potential loss related to the guarantee is approximately $12 million and SWEPCo’s is approximately $13 million assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, we believe that the fair value would produce a sufficient sales price to avoid any loss.

ENVIRONMENTAL CONTINGENCIES

Carbon Dioxide Public Nuisance Claims

In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority.  The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants.  The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming and sought injunctive relief in the form of specific emission reduction commitments from the defendants.  The trial court dismissed the lawsuits.

In September 2009, the Second Circuit Court of Appeals issued a ruling on appeal remanding the cases to the Federal District Court for the Southern District of New York.  The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate CO2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s administration to secure the relief sought in their complaints.  The court stated that Congress could enact comprehensive legislation to regulate CO2 emissions or that the Federal EPA could regulate CO2 emissions under existing CAA authorities and that either of these actions could override any decision made by the district court under federal common law.  The Second Circuit did not rule on whether the plaintiffs could proceed with their state common law nuisance claims.  In 2010, the U.S. Supreme Court granted the defendants’ petition for review.  In June 2011, the U.S. Supreme Court reversed and remanded the case to the Court of Appeals, finding that plaintiffs’ federal common law claims are displaced by the regulatory authority granted to the Federal EPA under the CAA.

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing.  An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision.  The petition was denied in January 2011.  Plaintiffs refiled their complaint in federal district court.  We believe the claims are without merit, and in addition to other defenses, are barred by the doctrine of collateral estoppel and the applicable statute of limitations.  We intend to vigorously defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.
 
50

 

Alaskan Villages’ Claims

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  The plaintiffs appealed the decision.  Briefing is complete and no date has been set for oral argument.  The defendants requested that the court defer setting this case for oral argument until after the Supreme Court issues its decision in the CO2 public nuisance case discussed above.  The court entered an order deferring argument until after June 2011 and the parties requested supplemental briefing on the impact of the Supreme Court’s decision.  We believe the action is without merit and intend to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, our generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials.  We currently incur costs to dispose of these substances safely.

In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M started remediation work in accordance with a plan approved by MDEQ.  I&M’s provision is approximately $11 million.  As the remediation work is completed, I&M’s cost may continue to increase as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ.  We cannot predict the amount of additional cost, if any.

Amos Plant – State and Federal Enforcement Proceedings

In March 2010, we received a letter from the West Virginia Department of Environmental Protection, Division of Air Quality (DAQ), alleging that at various times in 2007 through 2009 the units at Amos Plant reported periods of excess opacity (indicator of compliance with PM emission limits) that lasted for more than 30 consecutive minutes in a 24-hour period and that certain required notifications were not made.  We met with representatives of DAQ to discuss these occurrences and the steps we have taken to prevent a recurrence.  DAQ indicated that additional enforcement action may be taken, including imposition of a civil penalty of approximately $240 thousand.  We have denied that violations of the reporting requirements occurred and maintain that the proper reporting was done.  In March 2011, we resolved these issues through the entry of a consent order that included the payment of a $75 thousand civil penalty and certain improvements in our opacity reports.

In March 2010, we received a request to show cause from the Federal EPA alleging that certain reporting requirements under Superfund and the Emergency Planning and Community Right-to-Know Act had been violated and inviting us to engage in settlement negotiations.  The request includes a proposed civil penalty of approximately $300 thousand.  We indicated our willingness to engage in good faith negotiations and provided additional information to representatives of the Federal EPA.  We have not admitted that any violations occurred or that the amount of the proposed penalty is reasonable.
 
51

 

NUCLEAR CONTINGENCIES

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission.  We have a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S.  Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

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 significant turbine damage and a small fire on the electric generator.  This equipment, located in the turbine building, is separate and isolated from the nuclear reactor.  The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period.  The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $408 million.  Management believes that I&M should recover a significant portion of these 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.  The replacement of the repaired turbine rotors and other equipment is scheduled for the Unit 1 planned outage in the fall of 2011.

I&M maintains insurance through NEIL.  As of June 30, 2011, we recorded $60 million in Prepayments and Other Current Assets on our Condensed Consolidated Balance Sheets representing amounts under NEIL insurance policies.  Through June 30, 2011, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage.

NEIL is reviewing claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies.  The review by NEIL includes the timing of the unit’s return to service and whether the return should have occurred earlier reducing the amount received under the accidental outage policy.  The treatment of property damage costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.

OPERATIONAL CONTINGENCIES

Fort Wayne Lease

Since 1975, I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expired on February 28, 2010.  I&M negotiated with Fort Wayne to purchase the assets at the end of the lease, but no agreement was reached prior to the end of the lease.

I&M and Fort Wayne reached a settlement agreement.  The agreement, signed in October 2010, is subject to approval by the IURC.  I&M filed a petition with the IURC seeking approval of the agreement, including recovery in rates of payments made to Fort Wayne.  If the agreement is approved, I&M will purchase the remaining leased property and settle claims Fort Wayne asserted.  The agreement provides that I&M will pay Fort Wayne a total of $39 million, inclusive of interest, over 15 years and Fort Wayne will recognize that I&M is the exclusive electricity supplier in the Fort Wayne area.  In April 2011, the Indiana Office of Utility Consumer Counselor (OUCC) filed comments opposing portions of the settlement agreement.  An agreement with the OUCC was reached and hearing before the IURC occurred in June 2011.  IURC approval of the agreement is expected during the third quarter of 2011.  If the agreement is not approved by the IURC, the parties have the right to terminate the agreement and pursue other relief.
 
52

 

Enron Bankruptcy

In 2001, we purchased Houston Pipeline Company (HPL) from Enron.  Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.  In connection with our acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 55 billion cubic feet (BCF) of cushion gas required for the normal operation of the Bammel gas storage facility.  At the time of our acquisition of HPL, BOA and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of the cushion gas.  Also at the time of our acquisition, Enron and the BOA Syndicate released HPL from all prior and future liabilities and obligations in connection with the financing arrangement.  After the Enron bankruptcy, the BOA Syndicate informed HPL of a purported default by Enron under the terms of the financing arrangement.  This dispute was litigated in the Enron bankruptcy proceedings and in federal courts in Texas and New York.

In 2007, the judge in the New York action issued a decision on all claims, including those that were pending trial in Texas, granting BOA summary judgment and dismissing our claims.  In August 2008, the New York court entered a final judgment of $346 million.  In May 2009, the judge awarded $20 million of attorneys’ fees to BOA.  We appealed these awards and posted bonds covering the amounts.  In October 2010, the Court of Appeals affirmed the New York district court’s decision as to the final judgment of $346 million and reversed the New York district court decision as to the judgment dismissing our claims against BOA in the Southern District of Texas.

In 2005, we sold our interest in HPL for approximately $1 billion.  Although the assets were legally transferred, we were unable to determine all costs associated with the transfer until the BOA litigation was resolved.  We indemnified the buyer of HPL against any damages up to the purchase price resulting from the BOA litigation, including the right to use the 55 BCF of natural gas through 2031.  As a result, we deferred the entire gain related to the sale of HPL (approximately $380 million) pending resolution of the Enron and BOA disputes.

The deferred gain related to the sale of HPL, plus accrued interest and attorneys’ fees related to the New York court’s judgment was $448 million at December 31, 2010 and was included in Current Liabilities – Deferred Gain and Accrued Litigation Costs on the Condensed Consolidated Balance Sheet.

In February 2011, we reached a settlement covering all claims with BOA and Enron for $425 million.  As part of the settlement, we received title to the 55 BCF of natural gas in the Bammel storage facility and recorded this asset at fair value.  Under the HPL sales agreement, we have a service obligation to the buyer for the right to use the cushion gas through May 2031.  We recognized the obligation as a liability and will amortize it over the life of the agreement.

The settlement resulted in a pretax gain of $51 million and a net loss after tax of $22 million primarily due to an unrealized capital loss valuation allowance of $56 million.
 
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At the time of the settlement, the following table sets forth its impact on our 2011 financial statements:

 
 
(in millions)
 
Income Statement:
 
 
 
  Other Operation Expense - Pretax Gain on Settlement
  $ 51  
  Income Tax Expense
    73  
Net Loss After Tax
  $ (22 )
 
       
Cash Flow Statement:
       
  Net Income - Loss on Settlement with BOA and Enron
  $ (22 )
  Deferred Income Taxes
    91  
  Gain on Settlement with BOA and Enron
    (51 )
  Settlement of Litigation with BOA and Enron
    (211 )
  Accrued Taxes, Net
    (18 )
  Acquisition of Cushion Gas from BOA
    (214 )
Cash Paid
  $ (425 )
 
       
Balance Sheet:
       
  Deferred Charges and Other Noncurrent Assets - Gas Acquired
  $ 214  
  Deferred Credits and Other Noncurrent Liabilities - Gas Service Liability
    187  
  Accrued Taxes - Tax Benefit on Settlement with BOA and Enron
    18  
  Deferred Income Taxes - Deferred Tax Benefit on Gas Service Liability
    66  

Natural Gas Markets Lawsuits

In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity.  AEP was dismissed from the case.  A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies.  AEP (or a subsidiary) is among the companies named as defendants in some of these cases.  In 2008, we settled all of the cases pending against us in California.  In July 2011, the judge in the Federal District Court in Las Vegas granted summary judgment dismissing the cases where AEP companies were defendants.  Also in July 2011, the plaintiffs in these cases filed notices of appeal to the Ninth Circuit Court of Appeals.  We will continue to defend the remaining case in Ohio where an AEP company is a defendant and all appeals of the cases that were just dismissed by the federal judge in Las Vegas.   We believe the provision we have for the remaining cases is adequate.  We believe the remaining exposure is immaterial.

5.  ACQUISITION AND DISPOSITIONS

ACQUISITION

2010

Valley Electric Membership Corporation (Utility Operations segment)

In October 2010, SWEPCo purchased certain transmission and distribution assets of Valley Electric Membership Corporation (VEMCO) for approximately $102 million and began serving VEMCO’s 30,000 customers in Louisiana.

DISPOSITIONS

2010

Electric Transmission Texas LLC (ETT) (Utility Operations segment)

During the six months ended June 30, 2010, TCC and TNC sold, at cost, $64 million and $71 million, respectively, of transmission facilities to ETT.
 
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Intercontinental Exchange, Inc. (ICE) (All Other)

In April 2010, we sold our remaining 138,000 shares of ICE and recognized a $16 million gain ($10 million, net of tax).  We recorded the gain in Interest and Investment Income on our Condensed Consolidated Statements of Income for the three months ended June 30, 2010.

6.  BENEFIT PLANS

Components of Net Periodic Benefit Cost

The following tables provide the components of our net periodic benefit cost for the plans for the three and six months ended June 30, 2011 and 2010:

 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
Three Months Ended June 30,
 
Three Months Ended June 30,
 
 
2011
 
2010
 
2011
 
2010
 
 
(in millions)
 
Service Cost
  $ 18     $ 27     $ 10     $ 11  
Interest Cost
    60       64       27       28  
Expected Return on Plan Assets
    (78 )     (78 )     (27 )     (26 )
Amortization of Transition Obligation
    -       -       -       7  
Amortization of Net Actuarial Loss
    31       23       8       7  
Net Periodic Benefit Cost
  $ 31     $ 36     $ 18     $ 27  

 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
Six Months Ended June 30,
 
Six Months Ended June 30,
 
 
2011
 
2010
 
2011
 
2010
 
 
(in millions)
 
Service Cost
  $ 36     $ 55     $ 21     $ 23  
Interest Cost
    119       127       54       56  
Expected Return on Plan Assets
    (157 )     (156 )     (54 )     (52 )
Amortization of Transition Obligation
    -       -       -       14  
Amortization of Net Actuarial Loss
    61       45       15       14  
Net Periodic Benefit Cost
  $ 59     $ 71     $ 36     $ 55  

7.  BUSINESS SEGMENTS

As outlined in our 2010 Annual Report, our primary business is our electric utility operations.  Within our Utility Operations segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  While our Utility Operations segment remains our primary business segment, other segments include our AEP River Operations segment with significant barging activities and our Generation and Marketing segment, which includes our nonregulated generating, marketing and risk management activities primarily in the ERCOT market area and, to a lesser extent, Ohio in PJM and MISO.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.
 
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Our reportable segments and their related business activities are as follows:

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

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

Generation and Marketing
·  
Wind farms and marketing and risk management activities primarily in ERCOT and, to a lesser extent, Ohio in PJM and MISO.

The remainder of our activities is presented as All Other.  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 settle and expire in the fourth quarter of 2011.
·  
Revenue sharing related to the Plaquemine Cogeneration Facility which ends in the fourth quarter of 2011.

The tables below present our reportable segment information for the three and six months ended June 30, 2011 and 2010 and balance sheet information as of June 30, 2011 and December 31, 2010.  These amounts include certain estimates and allocations where necessary.

 
 
 
 
 
Nonutility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
 
 
 
 
 
 
 
Utility
 
AEP River
 
and
 
All Other
 
Reconciling
 
 
 
 
Operations
 
Operations
 
Marketing
 
(a)
 
 Adjustments
 
Consolidated
 
 
(in millions)
Three Months Ended June 30, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
 3,360 
 
$
 162 
 
$
 79 
 
$
 8 
 
$
 - 
 
$
 3,609 
Other Operating Segments
 
 
 29 
 
 
 4 
 
 
 - 
 
 
 2 
 
 
 (35)
 
 
 - 
Total Revenues
 
$
 3,389 
 
$
 166 
 
$
 79 
 
$
 10 
 
$
 (35)
 
$
 3,609 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
$
 356 
 
$
 (1)
 
$
 11 
 
$
 (13)
 
$
 - 
 
$
 353 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nonutility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
 
 
 
 
 
 
 
Utility
 
AEP River
 
and
 
All Other
 
Reconciling
 
 
 
 
Operations
 
Operations
 
Marketing
 
(a)
 
 Adjustments
 
Consolidated
 
 
(in millions)
Three Months Ended June 30, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
 3,186 
 
$
 127 
 
$
 42 
 
$
 5 
 
$
 - 
 
$
 3,360 
Other Operating Segments
 
 
 25 
 
 
 5 
 
 
 - 
 
 
 (1)
 
 
 (29)
 
 
 - 
Total Revenues
 
$
 3,211 
 
$
 132 
 
$
 42 
 
$
 4 
 
$
 (29)
 
$
 3,360 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
$
 132 
 
$
 (1)
 
$
 7 
 
$
 (1)
 
$
 - 
 
$
 137 

 
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Nonutility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
 
 
 
 
 
 
 
Utility
 
AEP River
 
and
 
All Other
 
Reconciling
 
 
 
 
Operations
 
Operations
 
Marketing
 
(a)
 
 Adjustments
 
Consolidated
 
 
(in millions)
Six Months Ended June 30, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
 6,857 
 
$
 329 
 
$
 141 
 
$
 12 
 
$
 - 
 
$
 7,339 
Other Operating Segments
 
 
 56 
 
 
 9 
 
 
 1 
 
 
 3 
 
 
 (69)
 
 
 - 
Total Revenues
 
$
 6,913 
 
$
 338 
 
$
 142 
 
$
 15 
 
$
 (69)
 
$
 7,339 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
$
 734 
 
$
 6 
 
$
 12 
 
$
 (44)
 
$
 - 
 
$
 708 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nonutility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
 
 
 
 
 
 
 
Utility
 
AEP River
 
and
 
All Other
 
Reconciling
 
 
 
 
Operations
 
Operations
 
Marketing
 
(a)
 
 Adjustments
 
Consolidated
 
 
(in millions)
Six Months Ended June 30, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
 6,592 
 
$
 248 
 
$
 89 
 
$
 - 
 
$
 - 
 
$
 6,929 
Other Operating Segments
 
 
 45 
 
 
 10 
 
 
 - 
 
 
 7 
 
 
 (62)
 
 
 - 
Total Revenues
 
$
 6,637 
 
$
 258 
 
$
 89 
 
$
 7 
 
$
 (62)
 
$
 6,929 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
$
 476 
 
$
 2 
 
$
 17 
 
$
 (12)
 
$
 - 
 
$
 483 

 
 
 
 
Nonutility Operations
 
 
   
 
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
Reconciling
 
 
 
 
 
Utility
 
AEP River
 
and
 
All Other
 
Adjustments
 
 
 
 
 
Operations
 
Operations
 
Marketing
 
(a)
 
(b)
 
 
Consolidated
 
 
(in millions)
 
June 30, 2011
 
 
 
 
 
 
 
 
   
 
 
 
 
 
Total Property, Plant and Equipment
  $ 53,735   $ 590   $ 591   $ 11     $ (258 )
 
$ 54,669  
Accumulated Depreciation and Amortization
    18,315     124     209     9       (52 )
 
  18,605  
Total Property, Plant and Equipment - Net
  $ 35,420   $ 466   $ 382   $ 2     $ (206 )
 
$ 36,064  
 
                                 
 
     
Total Assets
  $ 48,858   $ 647   $ 864   $ 15,974     $ (15,591 )
(c)
$ 50,752  
 
                                 
 
     
 
       
Nonutility Operations
               
 
     
 
             
Generation
       
Reconciling
 
 
     
 
Utility
 
AEP River
 
and
 
All Other
 
Adjustments
 
 
     
 
Operations
 
Operations
 
Marketing
 
(a)
 
(b)
 
 
Consolidated
 
 
(in millions)
 
December 31, 2010
                                 
 
     
Total Property, Plant and Equipment
  $ 52,822   $ 574   $ 584   $ 11     $ (251 )
 
$ 53,740  
Accumulated Depreciation and Amortization
    17,795     110     198     9       (46 )
 
  18,066  
Total Property, Plant and Equipment - Net
  $ 35,027   $ 464   $ 386   $ 2     $ (205 )
 
$ 35,674  
 
                                 
 
     
Total Assets
  $ 48,780   $ 621   $ 881   $ 15,942     $ (15,769 )
(c)
$ 50,455  

(a)
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 settle and expire in the fourth quarter of 2011.
·  
Revenue sharing related to the Plaquemine Cogeneration Facility which ends in the fourth quarter of 2011.
(b)
Includes eliminations due to an intercompany capital lease.
(c)
Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies.

 
57

 
8.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

We are 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, credit risk and, to a lesser extent, foreign currency exchange risk.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.  We manage these risks using derivative instruments.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Trading Strategies

Our strategy surrounding the use of derivative instruments for trading purposes focuses on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact.

Risk Management Strategies

Our strategy surrounding the use of derivative instruments focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  To accomplish our objectives, we primarily employ risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments.  Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.”  Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

We enter into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business.  We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio.  For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities.  We also engage in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies.  For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.”  The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.

The following table represents the gross notional volume of our outstanding derivative contracts as of June 30, 2011 and December 31, 2010:

Notional Volume of Derivative Instruments
 
 
 
   
 
 
 
 
Volume
 
 
 
June 30,
 
December 31,
 
Unit of
 
2011
 
2010
 
Measure
 
(in millions)
 
 
Commodity:
 
 
   
 
 
 
Power
    875       652  
MWHs
Coal
    48       63  
Tons
Natural Gas
    91       94  
MMBtus
Heating Oil and Gasoline
    7       6  
Gallons
Interest Rate
  $ 267     $ 171  
USD
 
               
 
Interest Rate and Foreign Currency
  $ 597     $ 907  
USD

 
58

 
Fair Value Hedging Strategies

We enter into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt.  Certain interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate.  Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.

Cash Flow Hedging Strategies

We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities.  We monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases.  We do not hedge all commodity price risk.

Our vehicle fleet and barge operations are exposed to gasoline and diesel fuel price volatility.  We enter into financial heating oil and gasoline derivative contracts in order to mitigate price risk of our future fuel purchases.  For disclosure purposes, these contracts are included with other hedging activity as “Commodity.”  We do not hedge all fuel price risk.

We enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure.  Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate.  We also enter into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt.  Our anticipated fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures.  We do not hedge all interest rate exposure.

At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers.  In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar.  We do not hedge all foreign currency exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities in the balance sheet at fair value.  The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes.  If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions.  In order to determine the relevant fair values of our derivative instruments, we also apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due.  Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions.  Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts.  Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles.  Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with our estimates of current market consensus for forward prices in the current period.  This is particularly true for longer term contracts.  Cash flows may vary based on market conditions, margin requirements and the timing of settlement of our risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the June 30, 2011 and December 31, 2010 balance sheets, we netted $16 million and $8 million,
 
59

 
 
respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $55 million and $109 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

The following tables represent the gross fair value impact of our derivative activity on our Condensed Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010:

Fair Value of Derivative Instruments
 
June 30, 2011
 
 
 
 
 
Risk Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a)(b)
 
Total
 
 
 
(in millions)
 
Current Risk Management Assets
  $ 669   $ 26   $ 6   $ (528 )   $ 173  
Long-term Risk Management Assets
    482     13     3     (155 )     343  
Total Assets
    1,151     39     9     (683 )     516  
 
                                 
Current Risk Management Liabilities
    636     14     2     (558 )     94  
Long-term Risk Management Liabilities
    317     6     1     (200 )     124  
Total Liabilities
    953     20     3     (758 )     218  
 
                                 
Total MTM Derivative Contract Net Assets
                                 
 (Liabilities)
  $ 198   $ 19   $ 6   $ 75     $ 298  
 
                                 
Fair Value of Derivative Instruments
 
December 31, 2010
 
 
 
 
 
Risk Management
                           
 
 
Contracts
 
Hedging Contracts
               
 
             
Interest Rate
               
 
             
and Foreign
               
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a)(b)
 
Total
 
 
 
(in millions)
 
Current Risk Management Assets
  $ 1,023   $ 18   $ 30   $ (839 )   $ 232  
Long-term Risk Management Assets
    546     12     2     (150 )     410  
Total Assets
    1,569     30     32     (989 )     642  
 
                                 
Current Risk Management Liabilities
    995     13     2     (881 )     129  
Long-term Risk Management Liabilities
    387     6     3     (255 )     141  
Total Liabilities
    1,382     19     5     (1,136 )     270  
 
                                 
Total MTM Derivative Contract Net Assets
                                 
 (Liabilities)
  $ 187   $ 11   $ 27   $ 147     $ 372  

 
(a)
Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the Condensed Consolidated Balance Sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."
 
(b)
Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."  Amounts also include dedesignated risk management contracts.

 
60

 
The tables below present our activity of derivative risk management contracts for the three and six months ended June 30, 2011 and 2010:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2011 and 2010
 
 
 
 
 
Location of Gain (Loss)
 
2011 
 
2010 
 
 
(in millions)
Utility Operations Revenue
 
$
 18 
 
$
 7 
Other Revenue
 
 
 13 
 
 
 8 
Regulatory Assets (a)
 
 
 (5)
 
 
 (14)
Regulatory Liabilities (a)
 
 
 5 
 
 
 (4)
Total Gain (Loss) on Risk Management Contracts
 
$
 31 
 
$
 (3)
 
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Six Months Ended June 30, 2011 and 2010
 
 
 
 
 
Location of Gain (Loss)
 
2011 
 
2010 
 
 
(in millions)
Utility Operations Revenue
 
$
 38 
 
$
 45 
Other Revenue
 
 
 15 
 
 
 9 
Regulatory Assets (a)
 
 
 (1)
 
 
 (3)
Regulatory Liabilities (a)
 
 
 11 
 
 
 27 
Total Gain (Loss) on Risk Management Contracts
 
$
 63 
 
$
 78 

(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheet.

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.”  Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the Condensed Consolidated Statements of Income on an accrual basis.

Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship.  Depending on the exposure, we designate a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes.  Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in Revenues on a net basis on the Condensed Consolidated Statements of Income.  Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in Revenues or Expenses on the Condensed Consolidated Statements of Income depending on the relevant facts and circumstances.  However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

Accounting for Fair Value Hedging Strategies

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change.
 
61

 

We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our Condensed Consolidated Statements of Income.  During the three and six months ended June 30, 2011, we recognized gains of $4 million and $8 million, respectively, on our outstanding hedging instruments and offsetting losses of $5 million and $9 million, respectively, on our long-term debt.  Hedge ineffectiveness was immaterial.  During the three and six months ended June 30, 2010, we recognized gains of $4 million and $4 million, respectively, on our outstanding hedging instruments and offsetting losses of $4 million and $4 million, respectively, on our long-term debt.  No hedge ineffectiveness was recognized.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets until the period the hedged item affects Net Income.  We recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal, natural gas and heating oil and gasoline designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our Condensed Consolidated Statements of Income, or in Regulatory Assets or Regulatory Liabilities on our Condensed Consolidated Balance Sheets, depending on the specific nature of the risk being hedged.  During the three and six months ended June 30, 2011 and 2010, we designated commodity derivatives as cash flow hedges.

We reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our Condensed Consolidated Statements of Income.  During the three and six months ended June 30, 2011 and 2010, we designated heating oil and gasoline derivatives as cash flow hedges.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur.  During the three and six months ended June 30, 2011 and 2010, we designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets into Depreciation and Amortization expense on our Condensed Consolidated Statements of Income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.  During the three and six months ended June 30, 2011 and 2010, we designated foreign currency derivatives as cash flow hedges.

During the three and six months ended June 30, 2011 and 2010, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.
 
62

 

The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2011 and 2010.  All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
 
For the Three Months Ended June 30, 2011
 
 
 
 
 
Interest Rate
   
 
 
 
 
 
 
and Foreign
   
 
 
 
Commodity
 
Currency
 
Total
 
 
(in millions)
 
Balance in AOCI as of March 31, 2011
  $ 8     $ 4     $ 12  
Changes in Fair Value Recognized in AOCI
    3       -       3  
Amount of (Gain) or Loss Reclassified from AOCI
                       
to Income Statement/within Balance Sheet:
                       
Utility Operations Revenue
    2       -       2  
Other Revenue
    (1 )     -       (1 )
Purchased Electricity for Resale
    (1 )     -       (1 )
Interest Expense
    -       1       1  
Regulatory Assets (a)
    1       -       1  
Regulatory Liabilities (a)
    -       -       -  
Balance in AOCI as of June 30, 2011
  $ 12     $ 5     $ 17  
 
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
 
For the Three Months Ended June 30, 2010
 
 
       
Interest Rate
         
 
       
and Foreign
         
 
Commodity
 
Currency
 
Total
 
 
(in millions)
 
Balance in AOCI as of March 31, 2010
  $ 2     $ (13 )   $ (11 )
Changes in Fair Value Recognized in AOCI
    1       (3 )     (2 )
Amount of (Gain) or Loss Reclassified from AOCI
                       
to Income Statement/within Balance Sheet:
                       
Utility Operations Revenue
    -       -       -  
Other Revenue
    (2 )     -       (2 )
Purchased Electricity for Resale
    1       -       1  
Interest Expense
    -       1       1  
Regulatory Assets (a)
    -       -       -  
Regulatory Liabilities (a)
    -       -       -  
Balance in AOCI as of June 30, 2010
  $ 2     $ (15 )   $ (13 )

 
63

 
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
 
For the Six Months Ended June 30, 2011
 
 
 
 
 
Interest Rate
   
 
 
 
 
 
 
and Foreign
   
 
 
 
Commodity
 
Currency
 
Total
 
 
(in millions)
 
Balance in AOCI as of December 31, 2010
  $ 7     $ 4     $ 11  
Changes in Fair Value Recognized in AOCI
    5       (1 )     4  
Amount of (Gain) or Loss Reclassified from AOCI
                       
to Income Statement/within Balance Sheet:
                       
Utility Operations Revenue
    2       -       2  
Other Revenue
    (2 )     -       (2 )
Purchased Electricity for Resale
    (1 )     -       (1 )
Interest Expense
    -       2       2  
Regulatory Assets (a)
    1       -       1  
Regulatory Liabilities (a)
    -       -       -  
Balance in AOCI as of June 30, 2011
  $ 12     $ 5     $ 17  
 
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
 
For the Six Months Ended June 30, 2010
 
 
       
Interest Rate
         
 
       
and Foreign
         
 
Commodity
 
Currency
 
Total
 
 
(in millions)
 
Balance in AOCI as of December 31, 2009
  $ (2 )   $ (13 )   $ (15 )
Changes in Fair Value Recognized in AOCI
    4       (4 )     -  
Amount of (Gain) or Loss Reclassified from AOCI
                       
to Income Statement/within Balance Sheet:
                       
Utility Operations Revenue
    -       -       -  
Other Revenue
    (3 )     -       (3 )
Purchased Electricity for Resale
    2       -       2  
Interest Expense
    -       2       2  
Regulatory Assets (a)
    1       -       1  
Regulatory Liabilities (a)
    -       -       -  
Balance in AOCI as of June 30, 2010
  $ 2     $ (15 )   $ (13 )
 
(a)
Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheet.
 

 
64

 
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets at June 30, 2011 and December 31, 2010 were:

Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet
 
June 30, 2011
 
 
 
 
   
 
   
 
 
 
 
 
 
Interest Rate
   
 
 
 
 
 
 
and Foreign
   
 
 
 
Commodity
 
Currency
 
Total
 
 
(in millions)
 
Hedging Assets (a)
  $ 21     $ 1     $ 22  
Hedging Liabilities (a)
    2       3       5  
AOCI Gain (Loss) Net of Tax
    12       5       17  
Portion Expected to be Reclassified to Net
                       
Income During the Next Twelve Months
    7       (2 )     5  
 
                       
Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet
 
December 31, 2010
 
 
                       
 
       
Interest Rate
         
 
       
and Foreign
         
 
Commodity
 
Currency
 
Total
 
 
(in millions)
 
Hedging Assets (a)
  $ 13     $ 25     $ 38  
Hedging Liabilities (a)
    2       4       6  
AOCI Gain (Loss) Net of Tax
    7       4       11  
Portion Expected to be Reclassified to Net
                       
Income During the Next Twelve Months
    3       (2 )     1  

(a)
Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on our Condensed Consolidated Balance Sheets.

The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.  As of June 30, 2011, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions is 36 months.

Credit Risk

We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  We use Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

We use standardized master agreements which may include collateral requirements.  These master agreements facilitate the netting of cash flows associated with a single counterparty.  Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk.  The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold.  The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy.  In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
 
65

 

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, we are obligated to post an additional amount of collateral if our credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and our total exposure.  On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts.  We do not anticipate a downgrade below investment grade.  The following table represents: (a) our aggregate fair value of such derivative contracts, (b) the amount of collateral we would have been required to post for all derivative and non-derivative contracts if our credit ratings had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of June 30, 2011 and December 31, 2010:

 
June 30,
 
December 31,
 
 
2011
 
2010
 
 
(in millions)
 
Liabilities for Derivative Contracts with Credit Downgrade Triggers
$ 29   $ 20  
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post
   34      45  
Amount Attributable to RTO and ISO Activities
  34     44  

In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million.  On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts.  We do not anticipate a non-performance event under these provisions.  The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of June 30, 2011 and December 31, 2010:

 
June 30,
 
December 31,
 
 
2011
 
2010
 
 
(in millions)
 
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements
$ 344   $ 401  
Amount of Cash Collateral Posted
  35     81  
Additional Settlement Liability if Cross Default Provision is Triggered
  179     213  

9.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.
 
66

 

For our commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated.  We typically obtain multiple broker quotes, which are non-binding in nature, but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, we average the quoted bid and ask prices.  In certain circumstances, we may discard a broker quote if it is a clear outlier.  We use a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated, we include these locations within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.

We utilize our trustee’s external pricing service in our estimate of the fair value of the underlying investments held in the nuclear trusts.  Our investment managers review and validate the prices utilized by the trustee to determine fair value.  We perform our own valuation testing to verify the fair values of the securities.  We receive audit reports of our trustee’s operating controls and valuation processes.  The trustee uses multiple pricing vendors for the assets held in the trusts.

Assets in the nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.  Fixed income securities do not trade on an exchange and do not have an official closing price.  Pricing vendors calculate bond valuations using financial models and matrices.  Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data.  Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data and economic events.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

Items classified as Level 2 are primarily investments in individual fixed income securities.  These fixed income securities are valued using models with input data as follows:

 
 
Type of Fixed Income Security
 
 
United States
 
 
 
State and Local
Type of Input
 
Government
 
Corporate Debt
 
Government
 
 
 
 
 
 
 
Benchmark Yields
 
X
 
X
 
X
Broker Quotes
 
X
 
X
 
X
Discount Margins
 
X
 
X
 
 
Treasury Market Update
 
X
 
 
 
 
Base Spread
 
X
 
X
 
X
Corporate Actions
 
 
 
X
 
 
Ratings Agency Updates
 
 
 
X
 
X
Prepayment Schedule and History
 
 
 
 
 
X
Yield Adjustments
 
X
 
 
 
 

Fair Value Measurements of Long-term Debt

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange.
 
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The book values and fair values of Long-term Debt as of June 30, 2011 and December 31, 2010 are summarized in the following table:

 
 
 
June 30, 2011
 
December 31, 2010
 
 
 
Book Value
 
Fair Value
 
Book Value
 
Fair Value
 
 
 
(in millions)
 
Long-term Debt
 
$
 16,635 
 
$
 18,251 
 
$
 16,811 
 
$
 18,285 

Fair Value Measurements of Other Temporary Investments

Other Temporary Investments include marketable securities that we intend to hold for less than one year, investments by our protected cell of EIS and funds held by trustees primarily for the repayment of debt.

The following is a summary of Other Temporary Investments:

 
 
June 30, 2011
 
 
 
 
Gross
 
Gross
 
Estimated
 
 
 
 
Unrealized
 
Unrealized
 
Fair
Other Temporary Investments
 
Cost
 
Gains
 
Losses
 
Value
 
 
(in millions)
Restricted Cash (a)
  $ 212   $ -   $ -   $ 212
Fixed Income Securities:
                       
Mutual Funds
    63     -     -     63
Variable Rate Demand Notes
    21     -     -     21
Equity Securities - Mutual Funds
    7     8     -     15
Total Other Temporary Investments
  $ 303   $ 8   $ -   $ 311
 
 
 
December 31, 2010
 
       
Gross
 
Gross
 
Estimated
 
       
Unrealized
 
Unrealized
 
Fair
Other Temporary Investments
 
Cost
 
Gains
 
Losses
 
Value
 
 
(in millions)
Restricted Cash (a)
  $ 225   $ -   $ -   $ 225
Fixed Income Securities:
                       
Mutual Funds
    69     -     -     69
Variable Rate Demand Notes
    97     -     -     97
Equity Securities - Mutual Funds
    18     7     -     25
Total Other Temporary Investments
  $ 409   $ 7   $ -   $ 416
 
(a)
Primarily represents amounts held for the repayment of debt.
 

The following table provides the activity for our debt and equity securities within Other Temporary Investments for the three and six months ended June 30, 2011 and 2010:

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2011
 
2010
 
2011
 
2010
 
(in millions)
Proceeds from Investment Sales
$ 51   $ 16   $ 247   $ 257
Purchases of Investments
  5     24     153     221
Gross Realized Gains on Investment Sales
  -     16     -     16
Gross Realized Losses on Investment Sales
  -     -     -     -

At June 30, 2011 and December 31, 2010, we had no Other Temporary Investments with an unrealized loss position.  At June 30, 2011, the fair value of fixed income securities are primarily debt based mutual funds with short and intermediate maturities and variable rate demand notes.  Mutual funds may be sold and do not contain maturity dates.
 
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Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

·  
Acceptable investments (rated investment grade or above when purchased).
·  
Maximum percentage invested in a specific type of investment.
·  
Prohibition of investment in obligations of AEP or its affiliates.
·  
Withdrawals permitted only for payment of decommissioning costs and trust expenses.

We maintain trust records for each regulatory jurisdiction.  These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities.  The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value.  I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose.  Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the equity and debt investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized gains and other-than-temporary impairments from securities in the trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.  The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities.  Regulatory approval is required to withdraw decommissioning funds.

The following is a summary of nuclear trust fund investments at June 30, 2011 and December 31, 2010:

 
June 30, 2011
 
December 31, 2010
 
 
Estimated
 
Gross
 
Other-Than-
 
Estimated
 
Gross
 
Other-Than-
 
 
Fair
 
Unrealized
 
Temporary
 
Fair
 
Unrealized
 
Temporary
 
 
Value
 
Gains
 
Impairments
 
Value
 
Gains
 
Impairments
 
 
(in millions)
 
Cash and Cash Equivalents
$ 17   $ -   $ -   $ 20   $ -   $ -  
Fixed Income Securities:
                                   
United States Government
  484     27     (1 )   461     23     (1 )
Corporate Debt
  57     3     (1 )   59     4     (2 )
State and Local Government
  338     1     (1 )   341     (1 )   -  
  Subtotal Fixed Income Securities
  879     31     (3 )   861     26     (3 )
Equity Securities - Domestic
  678     231     (105 )   634     183     (123 )
Spent Nuclear Fuel and
                                   
Decommissioning Trusts
$ 1,574   $ 262   $ (108 ) $ 1,515   $ 209   $ (126 )

 
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The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2011 and 2010:

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2011
 
2010
 
2011
 
2010
 
 
(in millions)
 
Proceeds from Investment Sales
$ 177   $ 360   $ 465   $ 592  
Purchases of Investments
  186     369     492     617  
Gross Realized Gains on Investment Sales
  7     1     12     6  
Gross Realized Losses on Investment Sales
  4     -     9     -  

The adjusted cost of debt securities was $848 million and $835 million as of June 30, 2011 and December 31, 2010, respectively.  The adjusted cost of equity securities was $447 million and $451 million as of June 30, 2011 and December 31, 2010, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at June 30, 2011 was as follows:

 
Fair Value
 
of Debt
 
Securities
 
(in millions)
Within 1 year
  $ 77
1 year – 5 years
    256
5 years – 10 years
    281
After 10 years
    265
Total
  $ 879

 
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Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2011 and December 31, 2010.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in our valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2011
 
 
 
   
 
   
 
   
 
   
 
 
 
Level 1
   
Level 2
   
Level 3
   
Other
   
Total
Assets:
 
(in millions)
 
 
 
   
 
   
 
   
 
   
 
Cash and Cash Equivalents (a)
  $ 208     $ -     $ -     $ 209     $ 417
 
                                     
Other Temporary Investments
                                     
Restricted Cash (a)
    160       -       -       52       212
Fixed Income Securities:
                                     
Mutual Funds
    63       -       -       -       63
Variable Rate Demand Notes
    -       21       -       -       21
Equity Securities - Mutual Funds (b)
    15       -       -       -       15
Total Other Temporary Investments
    238       21       -       52       311
 
                                     
Risk Management Assets
                                     
Risk Management Commodity Contracts (c) (f)
    17       1,006       113       (686 )     450
Cash Flow Hedges:
                                     
Commodity Hedges (c)
    8       30       -       (17 )     21
Interest Rate/Foreign Currency Hedges
    -       1       -       -       1
Fair Value Hedges
    -       8       -       -       8
Dedesignated Risk Management Contracts (d)
    -       -       -       36       36
Total Risk Management Assets
    25       1,045       113       (667 )     516
 
                                     
Spent Nuclear Fuel and Decommissioning Trusts
                                     
Cash and Cash Equivalents (e)
    -       5       -       12       17
Fixed Income Securities:
                                     
United States Government
    -       484       -       -       484
Corporate Debt
    -       57       -       -       57
State and Local Government
    -       338       -       -       338
Subtotal Fixed Income Securities
    -       879       -       -       879
Equity Securities - Domestic (b)
    678       -       -       -       678
Total Spent Nuclear Fuel and Decommissioning Trusts
    678       884       -       12       1,574
 
                                     
Total Assets
  $ 1,149     $ 1,950     $ 113     $ (394 )   $ 2,818
 
                                     
Liabilities:
                                     
 
                                     
Risk Management Liabilities
                                     
Risk Management Commodity Contracts (c) (f)
  $ 20     $ 882     $ 36     $ (725 )   $ 213
Cash Flow Hedges:
                                     
Commodity Hedges (c)
    2       17       -       (17 )     2
Interest Rate/Foreign Currency Hedges
    -       3       -       -       3
Total Risk Management Liabilities
  $ 22     $ 902     $ 36     $ (742 )   $ 218

 
71

 


Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2010
 
 
 
   
 
   
 
   
 
   
 
 
 
Level 1
   
Level 2
   
Level 3
   
Other
   
Total
Assets:
 
(in millions)
 
 
 
   
 
   
 
   
 
   
 
Cash and Cash Equivalents (a)
  $ 170     $ -     $ -     $ 124     $ 294
 
                                     
Other Temporary Investments
                                     
Restricted Cash (a)
    184       -       -       41       225
Fixed Income Securities:
                                     
Mutual Funds
    69       -       -       -       69
Variable Rate Demand Notes
    -       97       -       -       97
Equity Securities - Mutual Funds (b)
    25       -       -       -       25
Total Other Temporary Investments
    278       97       -       41       416
 
                                     
Risk Management Assets
                                     
Risk Management Commodity Contracts (c) (g)
    20       1,432       112       (1,013 )     551
Cash Flow Hedges:
                                     
Commodity Hedges (c)
    11       17       -       (15 )     13
Interest Rate/Foreign Currency Hedges
    -       25       -       -       25
Fair Value Hedges
    -       7       -       -       7
Dedesignated Risk Management Contracts (d)
    -       -       -       46       46
Total Risk Management Assets
    31       1,481       112       (982 )     642
 
                                     
Spent Nuclear Fuel and Decommissioning Trusts
                                     
Cash and Cash Equivalents (e)
    -       8       -       12       20
Fixed Income Securities:
                                     
United States Government
    -       461       -       -       461
Corporate Debt
    -       59       -       -       59
State and Local Government
    -       341       -       -       341
Subtotal Fixed Income Securities
    -       861       -       -       861
Equity Securities - Domestic (b)
    634       -       -       -       634
Total Spent Nuclear Fuel and Decommissioning Trusts
    634       869       -       12       1,515
 
                                     
Total Assets
  $ 1,113     $ 2,447     $ 112     $ (805 )   $ 2,867
 
                                     
Liabilities:
                                     
 
                                     
Risk Management Liabilities
                                     
Risk Management Commodity Contracts (c) (g)
  $ 25     $ 1,325     $ 27     $ (1,114 )   $ 263
Cash Flow Hedges:
                                     
Commodity Hedges (c)
    4       13       -       (15 )     2
Interest Rate/Foreign Currency Hedges
    -       4       -       -       4
Fair Value Hedges
    -       1       -       -       1
Total Risk Management Liabilities
  $ 29     $ 1,343     $ 27     $ (1,129 )   $ 270

(a)
Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties.  Level 1 amounts primarily represent investments in money market funds.
(b)
Amounts represent publicly traded equity securities and equity-based mutual funds.
(c)
Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.''
(d)
Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for ''Derivatives and Hedging.''  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This MTM value will be amortized into revenues over the remaining life of the contracts.
(e)
Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions.  Level 2 amounts primarily represent investments in money market funds.
 
 
72

 
 
(f)
The June 30, 2011 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures ($1) million in 2011, $3 million in periods 2012-2014 and ($5) million in periods 2015-2018;  Level 2 matures $13 million in 2011, $75 million in periods 2012-2014, $18 million in periods 2015-2016 and $18 million in periods 2017-2028;  Level 3 matures $11 million in 2011, $25 million in periods 2012-2014, $15 million in periods 2015-2016 and $26 million in periods 2017-2028.  Risk management commodity contracts are substantially comprised of power contracts.
(g)
The December 31, 2010 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures ($2) million in 2011, $2 million in periods 2012-2014 and ($5) million in periods 2015-2018;  Level 2 matures $13 million in 2011, $66 million in periods 2012-2014, $12 million in periods 2015-2016 and $16 million in periods 2017-2028;  Level 3 matures $18 million in 2011, $24 million in periods 2012-2014, $16 million in periods 2015-2016 and $27 million in periods 2017-2028.  Risk management commodity contracts are substantially comprised of power contracts.

There were no transfers between Level 1 and Level 2 during the six months ended June 30, 2011 and 2010.

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as Level 3 in the fair value hierarchy:

 
 
Net Risk
 
 
 
Management
 
Three Months Ended June 30, 2011
 
Assets (Liabilities)
 
 
 
(in millions)
 
Balance as of March 31, 2011
  $ 73  
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
    (10 )
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
       
Relating to Assets Still Held at the Reporting Date (a)
    10  
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
    -  
Purchases, Issuances and Settlements (c)
    14  
Transfers into Level 3 (d) (f)
    3  
Transfers out of Level 3 (e) (f)
    (4 )
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
    (9 )
Balance as of June 30, 2011
  $ 77  

 
 
Net Risk Management
 
Three Months Ended June 30, 2010
 
Assets (Liabilities)
 
 
 
(in millions)
 
Balance as of March 31, 2010
  $ 116  
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
    (25 )
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
       
Relating to Assets Still Held at the Reporting Date (a)
    10  
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
    -  
Purchases, Issuances and Settlements (c)
    14  
Transfers into Level 3 (d) (f)
    1  
Transfers out of Level 3 (e) (f)
    (6 )
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
    (10 )
Balance as of June 30, 2010
  $ 100  
 
 
 
Net Risk Management
 
Six Months Ended June 30, 2011
 
Assets (Liabilities)
 
 
 
(in millions)
 
Balance as of December 31, 2010
  $ 85  
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
    (9 )
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
       
Relating to Assets Still Held at the Reporting Date (a)
    7  
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
    -  
Purchases, Issuances and Settlements (c)
    6  
Transfers into Level 3 (d) (f)
    4  
Transfers out of Level 3 (e) (f)
    (12 )
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
    (4 )
Balance as of June 30, 2011
  $ 77  

 
73

 
 
 
Net Risk Management
 
Six Months Ended June 30, 2010
 
Assets (Liabilities)
 
 
 
(in millions)
 
Balance as of December 31, 2009
  $ 62  
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
    4  
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
       
Relating to Assets Still Held at the Reporting Date (a)
    33  
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
    -  
Purchases, Issuances and Settlements (c)
    (13 )
Transfers into Level 3 (d) (f)
    12  
Transfers out of Level 3 (e) (f)
    (5 )
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
    7  
Balance as of June 30, 2010
  $ 100  

(a)
Included in revenues on our Condensed Consolidated Statements of Income.
(b)
Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)
Represents the settlement of risk management commodity contracts for the reporting period.
(d)
Represents existing assets or liabilities that were previously categorized as Level 2.
(e)
Represents existing assets or liabilities that were previously categorized as Level 3.
(f)
Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(g)
Relates to the net gains (losses) of those contracts that are not reflected on our Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory liabilities/assets.

10.  INCOME TAXES

We, along with our subsidiaries, file a consolidated federal income tax return.  The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense.  The tax benefit of the Parent is allocated to our subsidiaries with taxable income.  With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

We are no longer subject to U.S. federal examination for years before 2001.  We have completed the exam for the years 2001 through 2006 and have issues that we are pursuing at the appeals level.  In April 2011, the IRS’s examination of the years 2007 and 2008 was concluded with a settlement of all outstanding issues.  The settlement will not have a material impact on net income, cash flows or financial condition.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, we accrue interest on these uncertain tax positions.  We are not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on net income.

We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions.  These taxing authorities routinely examine our tax returns and we are currently under examination in several state and local jurisdictions.  We believe that we have filed tax returns with positions that may be challenged by these tax authorities.  Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and the ultimate resolution of these audits will not materially impact net income.  With few exceptions, we are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2000.

For a discussion of the tax implications of our settlement with BOA and Enron, see “Enron Bankruptcy” section of Note 4.
 
74

 

Federal Tax 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 six months ended June 30, 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.

The Small Business Jobs Act (the Act) was enacted in September 2010.  Included in the Act was a one-year extension of the 50% bonus depreciation provision.  The Tax Relief, Unemployment Insurance Reauthorization and the Job Creation Act of 2010 extended the life of research and development, employment and several energy tax credits originally scheduled to expire at the end of 2010.  In addition, the Act extended the time for claiming bonus depreciation and increased the deduction to 100% for part of 2010 and 2011.  The enacted provisions will not have a material impact on net income or financial condition.

State Tax Legislation

Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rates from 8.5% to 6.5%.  The current 8.5% Indiana corporate income tax rate is scheduled for a 0.5% reduction each year beginning after June 30, 2012 with the final reduction occurring in years beginning after June 30, 2015.  In addition, Michigan repealed its Business Tax regime in May 2011 and replaced it with a traditional corporate net income tax with a rate of 6%.  The enacted provisions will not have a material impact on net income, cash flows or financial condition.

11.  FINANCING ACTIVITIES
 
Long-term Debt
Type of Debt
 
June 30, 2011
 
December 31, 2010
 
 
 
(in millions)
 
Senior Unsecured Notes
  $ 11,750   $ 11,669  
Pollution Control Bonds
    2,153     2,263  
Notes Payable
    347     396  
Securitization Bonds
    1,755     1,847  
Junior Subordinated Debentures
    315     315  
Spent Nuclear Fuel Obligation (a)
    265     265  
Other Long-term Debt
    92     91  
Unamortized Discount (net)
    (42 )   (35 )
Total Long-term Debt Outstanding
    16,635     16,811  
Less Portion Due Within One Year
    1,071     1,309  
Long-term Portion
  $ 15,564   $ 15,502  

(a)
Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal.  The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983.  Trust fund assets related to this obligation were $307 million at June 30, 2011 and December 31, 2010, and are included in Spent Nuclear Fuel and Decommissioning Trusts on our Condensed Consolidated Balance Sheets.

 
75

 
Long-term debt and other securities issued, retired and principal payments made during the first six months of 2011 are shown in the tables below:

 
 
 
 
Principal
 
Interest
 
 
Company
 
Type of Debt
 
Amount
 
Rate
 
Due Date
Issuances:
 
 
(in millions)
(%)
 
 
APCo
 
Senior Unsecured Notes
 
$
 350 
 
4.60 
 
2021 
APCo
 
Pollution Control Bonds
 
 
 65 
 
2.00 
 
2012 
APCo
 
Pollution Control Bonds
 
 
 75 
(a)
Variable
 
2036 
APCo
 
Pollution Control Bonds
 
 
 54 
(a)
Variable
 
2042 
APCo
 
Pollution Control Bonds
 
 
 50 
(a)
Variable
 
2036 
APCo
 
Pollution Control Bonds
 
 
 50 
(a)
Variable
 
2042 
I&M
 
Pollution Control Bonds
 
 
 52 
(a)
Variable
 
2021 
I&M
 
Pollution Control Bonds
 
 
 25 
(a)
Variable
 
2019 
OPCo
 
Pollution Control Bonds
 
 
 50 
(a)
Variable
 
2014 
PSO
 
Senior Unsecured Notes
 
 
 250 
 
4.40 
 
2021 
PSO
 
Notes Payable
 
 
 2 
 
3.00 
 
2026 
TCC
 
Pollution Control Bonds
 
 
 60 
(a)
1.125 
 
2012 
Total Issuances
 
 
 
$
 1,083 
(b)
 
 
 

(a)
These pollution control bonds are subject to redemption earlier than the maturity date.  Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year on our Condensed Consolidated Balance Sheets.
(b)
Amount indicated on the statement of cash flows of $1,074 million is net of issuance costs and premium or discount.

 
 
 
 
Principal
 
Interest
 
 
Company
 
Type of Debt
 
Amount Paid
 
Rate
 
Due Date
Retirements and
 
 
(in millions)
(%)
 
 
   Principal Payments:
 
 
 
 
 
 
 
 
 
APCo
 
Pollution Control Bonds
 
$
 75 
 
Variable
 
2036 
APCo
 
Pollution Control Bonds
 
 
 54 
 
Variable
 
2042 
APCo
 
Pollution Control Bonds
 
 
 50 
 
Variable
 
2042 
APCo
 
Pollution Control Bonds
 
 
 50 
 
Variable
 
2036 
APCo
 
Senior Unsecured Notes
 
 
 250 
 
5.55 
 
2011 
I&M
 
Pollution Control Bonds
 
 
 52 
 
Variable
 
2021 
I&M
 
Pollution Control Bonds
 
 
 25 
 
Variable
 
2019 
I&M
 
Notes Payable
 
 
 13 
 
5.16 
 
2014 
I&M
 
Notes Payable
 
 
 15 
 
5.44 
 
2013 
I&M
 
Notes Payable
 
 
 11 
 
Variable
 
2015 
OPCo
 
Pollution Control Bonds
 
 
 65 
 
Variable
 
2036 
OPCo
 
Pollution Control Bonds
 
 
 50 
 
Variable
 
2014 
OPCo
 
Pollution Control Bonds
 
 
 50 
 
Variable
 
2014 
PSO
 
Senior Unsecured Notes
 
 
 200 
 
6.00 
 
2032 
PSO
 
Senior Unsecured Notes
 
 
 75 
 
4.70 
 
2011 
 
 
 
 
 
 
 
 
 
 
Non-Registrant:
 
 
 
 
 
 
 
 
 
AEP Subsidiaries
 
Notes Payable
 
 
 5 
 
Variable
 
2017 
AEP Subsidiaries
 
Notes Payable
 
 
 6 
 
Variable
 
2011 
AEGCo
 
Senior Unsecured Notes
 
 
 4 
 
6.33 
 
2037 
TCC
 
Securitization Bonds
 
 
 34 
 
5.96 
 
2013 
TCC
 
Securitization Bonds
 
 
 58 
 
4.98 
 
2013 
TCC
 
Pollution Control Bonds
 
 
 121 
 
5.125 
 
2011 
Total Retirements and
 
 
 
 
 
 
 
 
 
   Principal Payments
 
 
 
$
 1,263 
 
 
 
 

In July 2011, SWEPCo retired $41 million of 4.5% Pollution Control Bonds due in 2011.
 
76

 

In July 2011, AEGCo remarketed $45 million of variable rate Pollution Control Bonds which may be tendered for purchase at the option of the holder.  The Pollution Control Bonds are supported by letters of credit, which expire in 2014.

In July 2011, I&M retired $2 million of Notes Payable related to DCC Fuel.

As of June 30, 2011, trustees held, on our behalf, $478 million of our reacquired Pollution Control Bonds.

Dividend Restrictions

Parent Restrictions

The holders of our common stock are entitled to receive the dividends declared by our Board of Directors provided funds are legally available for such dividends.  Our income derives from our common stock equity in the earnings of our utility subsidiaries.

Pursuant to the leverage restrictions in our credit agreements, we must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.  The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend.  The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements.  None of AEP’s retained earnings were restricted for the purpose of the payment of dividends.

We have issued $315 million of Junior Subordinated Debentures.  The debentures will mature on March 1, 2063, subject to extensions to no later than March 1, 2068, and are callable at par any time on or after March 1, 2013.  We have the option to defer interest payments on the 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 do not anticipate any deferral of those interest payments in the foreseeable future.

Utility Subsidiaries’ Restrictions

Various charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.”  The term “capital account” is not defined in the Federal Power Act or its regulations.  Management understands “capital account” to mean the par value of the common stock multiplied by the number of shares outstanding.  This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings.

Short-term Debt
 
 
   
 
   
 
   
 
 
 
 
 
   
 
   
 
   
 
 
Our outstanding short-term debt was as follows:
 
 
   
 
   
 
   
 
 
 
 
 
   
 
   
 
   
 
 
 
 
June 30, 2011
 
December 31, 2010
 
 
Outstanding
   
Interest
 
Outstanding
   
Interest
Type of Debt
 
Amount
   
Rate (a)
 
Amount
   
Rate (a)
 
 
(in millions)
   
 
   
(in millions)
   
 
 
Securitized Debt for Receivables (b)
  $ 695       0.23 %   $ 690       0.31 %
Commercial Paper
    944       0.41 %     650       0.52 %
Line of Credit – Sabine Mining Company (c)
    -       - %     6       2.15 %
Total Short-term Debt
  $ 1,639             $ 1,346          

(a)
Weighted average rate.
(b)
Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance.
(c)
Sabine Mining Company is a consolidated variable interest entity.  This line of credit does not reduce available liquidity under AEP's credit facilities.

 
77

 
Credit Facilities

We have two $1.5 billion credit facilities, under which we may issue up to $1.35 billion as letters of credit.  In July 2011, we replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015.  As of June 30, 2011, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $132 million.

In March 2011, we terminated a $478 million credit agreement that was scheduled to mature in April 2011 and was used to support $472 million of variable rate Pollution Control Bonds.  In March 2011, we remarketed $357 million of variable rate Pollution Control Bonds using bilateral letters of credit for $361 million to support the remarketed Pollution Control Bonds.  The remaining $115 million of Pollution Control Bonds were reacquired and are held by trustees.

Securitized Accounts Receivable – AEP Credit

AEP Credit has a receivables securitization agreement with bank conduits.  Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries.  AEP Credit continues to service the receivables.  These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables and accelerate AEP Credit’s cash collections.

In July 2011, AEP Credit renewed its receivables securitization agreement.  The agreement provides commitments of $750 million from bank conduits to finance receivables from AEP Credit with an increase to $800 million for the months of July, August and September to accommodate seasonal demand.  A commitment of $375 million, with the seasonal increase to $425 million for the months of July, August and September, expires in June 2012 and the remaining commitment of $375 million expires in June 2014.

Accounts receivable information for AEP Credit is as follows:

 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2011
 
2010
 
2011
 
2010
 
 
(dollars in millions)
 
Effective Interest Rates on Securitization of
 
 
   
 
   
 
   
 
 
Accounts Receivable
    0.26 %     0.31 %     0.28 %     0.27 %
Net Uncollectible Accounts Receivable
                               
Written Off
  $ 6     $ 4     $ 17     $ 12  

 
 
June 30,
   
December 31,
 
 
 
2011
   
2010
 
 
 
(in millions)
 
Accounts Receivable Retained Interest and Pledged as Collateral
 
 
   
 
 
  Less Uncollectible Accounts
  $ 1,001     $ 923  
Total Principal Outstanding
    695       690  
Delinquent Securitized Accounts Receivable
    39       50  
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable
    22       26  
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable
    413       354  

Customer accounts receivable retained and securitized for our operating companies are managed by AEP Credit.  AEP Credit’s delinquent customer accounts receivable represents accounts greater than 30 days past due.
 
78

 

12.  COST REDUCTION INITIATIVES

In April 2010, we began initiatives to decrease both labor and non-labor expenses with a goal of achieving significant reductions in operation and maintenance expenses.  A total of 2,461 positions was eliminated across the AEP System as a result of process improvements, streamlined organizational designs and other efficiencies.  Most of the affected employees terminated employment May 31, 2010.  The severance program provided two weeks of base pay for every year of service along with other severance benefits.

We recorded a charge of $293 million to Other Operation expense during the second quarter of 2010 primarily related to severance benefits as the result of headcount reduction initiatives.

The following table shows the cost reduction activity for the six months ended June 30, 2011:

 
 
Total
 
 
 
(in millions)
 
Balance as of December 31, 2010
  $ 17  
Incurred
    -  
Settled
    (9 )
Adjustments
    (2 )
Balance as of June 30, 2011
  $ 6  

The remaining accruals are included primarily in Other Current Liabilities on the Condensed Consolidated Balance Sheets.
 
 
79

 
 

APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

 
80

 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Regulatory Activity

Virginia Regulatory Activity

In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012.  The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law. APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing.  If approved, APCo’s net base rate increase would be $75 million.  In July 2011, an Attorney General witness recommended an $80 million reduction in APCo’s requested rate year capacity charges.    See “2011 Virginia Biennial Base Rate Case” section of Note 3.

West Virginia Regulatory Activity

In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $46 million based upon a 10% return on common equity.  The order also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011.  See “Mountaineer Carbon Capture and Storage Project Product Validation Facility” section below.  In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and $14 million of previously expensed costs related to the 2010 cost reduction initiatives, each over a period of seven years.   See “2010 West Virginia Base Rate Case” section of Note 3.

In a November 2009 proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division.  The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources.  Merger approvals from the WVPSC, Virginia SCC and the FERC are required.  No merger approval filings have been made.  See “WPCo Merger with APCo” section of Note 3.

Mountaineer Carbon Capture and Storage Project Product Validation Facility (PVF)

APCo and ALSTOM Power, Inc., 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 May 2011, the PVF ended operations and decommissioning of the facility began.

In APCo’s May 2010 West Virginia base rate filing, APCo requested rate base treatment of the PVF including recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In March 2011, a WVPSC order denied the request for rate base treatment of the PVF largely due to its experimental operation.  The base rate order provided that should APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the PVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base.  As a result, APCo recorded a pretax write-off of $41 million ($26 million net of tax) in the first quarter of 2011.  As of June 30, 2011, APCo has recorded a noncurrent regulatory asset of $19 million related to the PVF.  If APCo cannot recover its remaining PVF investment and related accretion expenses, it would reduce future net income and cash flows.  See “Mountaineer Carbon Capture and Storage Project” section of Note 3.

Carbon Capture and Sequestration Project with the Department of Energy (DOE) (Commercial Scale Project)

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility at the Mountaineer Plant.  AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project.  The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million.  In July 2011, management informed the DOE that it will complete
 
81

 
 
a Front-End Engineering and Design study during the third quarter of 2011, but it is postponing any further CCS project activities because of the uncertainty about the regulation of CO2.  As of June 30, 2011, the project has incurred $30 million in total costs and has received $10 million of DOE eligible funding resulting in a $20 million net balance recorded in the Condensed Consolidated Balance Sheets.  Requests for recovery are in process in Michigan, Ohio and Virginia.  If the allocated costs of the CCS project cannot be recovered, it would reduce future net income and cash flows.  See “Mountaineer Carbon Capture and Storage Project” section of Note 3.

Proposed Acquisition of Dresden Plant

During the first quarter of 2011, APCo and AEGCo filed with the Virginia and West Virginia regulatory commissions seeking approval for APCo’s purchase of the partially completed Dresden Plant from AEGCo at cost.    In June 2011 and July 2011, the WVPSC and the Virginia SCC, respectively, issued orders approving the acquisition.  The transfer must also be approved by the Ohio Power Siting Board.  Management expects approval from the Ohio Power Siting Board allowing the transfer to occur in the third quarter of 2011.  The Dresden Plant is located near Dresden, Ohio and is a natural gas, combined cycle power plant.  AEGCo resumed construction in the first quarter of 2011 following a suspension in 2009 due to economic conditions.  When completed, the Dresden Plant will have a generating capacity of 580 MW.

Litigation and Environmental Issues

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 162.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 227 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
KWH Sales/Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summary of KWH Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 2,367 
 
 
 2,291 
 
 
 6,326 
 
 
 6,820 
 
Commercial
 
 1,696 
 
 
 1,750 
 
 
 3,394 
 
 
 3,536 
 
Industrial
 
 2,699 
 
 
 2,722 
 
 
 5,318 
 
 
 5,186 
 
Miscellaneous
 
 204 
 
 
 213 
 
 
 414 
 
 
 435 
Total Retail
 
 6,966 
 
 
 6,976 
 
 
 15,452 
 
 
 15,977 
 
 
 
 
 
 
 
 
 
 
 
 
Wholesale
 
 2,336 
 
 
 1,416 
 
 
 4,163 
 
 
 3,119 
 
 
 
 
 
 
 
 
 
 
 
 
Total KWHs
 
 9,302 
 
 
 8,392 
 
 
 19,615 
 
 
 19,096 

 
82

 
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.

Summary of Heating and Cooling Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
June 30,
 
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in degree days)
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 56 
 
 
 34 
 
 
 1,387 
 
 
 1,611 
Normal - Heating (b)
 
 100 
 
 
 101 
 
 
 1,437 
 
 
 1,440 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 464 
 
 
 540 
 
 
 470 
 
 
 540 
Normal - Cooling (b)
 
 348 
 
 
 342 
 
 
 354 
 
 
 348 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Eastern 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.

 
83

 
Second Quarter of 2011 Compared to Second Quarter of 2010
 
 
 
 
 
Reconciliation of Second Quarter of 2010 to Second Quarter of 2011
 
Net Income (Loss)
 
(in millions)
 
 
 
 
 
Second Quarter of 2010
  $ (20 )
 
       
Changes in Gross Margin:
       
Retail Margins
    10  
Off-system Sales
    3  
Transmission Revenue
    4  
Total Change in Gross Margin
    17  
 
       
Changes in Expenses and Other:
       
Other Operation and Maintenance
    53  
Depreciation and Amortization
    6  
Taxes Other Than Income Taxes
    4  
Carrying Costs Income
    (4 )
Other Income
    1  
Interest Expense
    (1 )
Total Change in Expenses and Other
    59  
 
       
Income Tax Expense
    (24 )
 
       
Second Quarter of 2011
  $ 32  

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 $10 million primarily due to the following:
 
·
A $27 million increase due to higher base rates in Virginia and West Virginia.
 
·
A $6 million increase due to lower capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia.
 
These increases were partially offset by:
 
·
A $21 million decrease due to the expiration of E&R cost recovery in Virginia.
 
·
A $3 million decrease in weather-related usage primarily due to a 14% decrease in cooling degree days.
·
Margins from Off-system Sales increased $3 million primarily due to higher physical sales volumes.
·
Transmission Revenue increased $4 million primarily due to the Transmission Agreement modification effective November 2010.

 
84

 
Expenses and Other and Income Tax Expense changed between years as follows:
 
·
Other Operation and Maintenance expenses decreased $53 million primarily due to the following:
 
·
A $55 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
 
·
A $54 million decrease due to the second quarter 2010 write-off of the Virginia share of the Mountaineer Carbon Capture and Storage Project Product Validation Facility as denied for recovery by the Virginia SCC.
 
These decreases were partially offset by:
 
·
A $25 million increase due to the second quarter 2010 deferral of 2009 storm costs as allowed by the Virginia SCC.
 
·
An $18 million increase in storm-related expenses. 
 
·
A $5 million increase in transmission expenses primarily due to the Transmission Agreement modification effective November 2010.
 · Depreciation and Amortization expenses decreased $6 million primarily due to the expiration of E&R amortization of deferred carrying costs in Virginia, partially offset by an increased depreciation base resulting from environmental upgrades at the Amos Plant.
 · Taxes Other Than Income Taxes decreased $4 million primarily due to recording a West Virginia franchise tax audit settlement and additional employer payroll taxes incurred related to the cost reduction initiatives in the second quarter of 2010.
 ·
Carrying Costs Income decreased $4 million primarily due to decreased environmental deferrals in Virginia.
 · Income Tax Expense increased $24 million primarily due to an increase in pretax book income. 

 
85

 
Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010
 
 
 
 
 
 
Reconciliation of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2011
Net Income (Loss)
(in millions)
 
 
 
 
 
Six Months Ended June 30, 2010
 
$
 51 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
Retail Margins
 
 
 (50)
 
Off-system Sales
 
 
 5 
 
Transmission Revenue
 
 
 6 
 
Other Revenues
 
 
 (1)
 
Total Change in Gross Margin
 
 
 (40)
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
Other Operation and Maintenance
 
 
 61 
 
Depreciation and Amortization
 
 
 14 
 
Taxes Other Than Income Taxes
 
 
 3 
 
Carrying Costs Income
 
 
 (6)
 
Other Income
 
 
 1 
 
Interest Expense
 
 
 (3)
 
Total Change in Expenses and Other
 
 
 70 
 
 
 
 
 
 
Income Tax Expense
 
 
 (10)
 
 
 
 
 
 
Six Months Ended June 30, 2011
 
$
 71 
 

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

·
Retail Margins decreased $50 million primarily due to the following:
 
·
A $37 million decrease due to the expiration of E&R cost recovery in Virginia.
 
·
A $22 million decrease in variable electric generation expenses.
 
·
A $19 million decrease in weather-related usage primarily due to a 14% decrease in heating degree days and a 13% decrease in cooling degree days.
 
·
A $10 million decrease in residential and commercial margins primarily due to lower non-weather related usage.
 
These decreases were partially offset by:
 
·
A $27 million increase due to lower capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia.
 
·
A $27 million increase due to higher base rates in Virginia and West Virginia.
·
Margins from Off-system Sales increased $5 million primarily due to higher physical sales volumes and higher trading and marketing margins.
·
Transmission Revenue increased $6 million primarily due to the Transmission Agreement modification effective November 2010.

 
86

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

·
Other Operation and Maintenance expenses decreased $61 million primarily due to the following:
 
·
A $55 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
 
·
A $54 million decrease due to the second quarter 2010 write-off of the Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC.
 
·
A $32 million decrease due to the first quarter 2011 deferral of 2010 storm costs and costs related to 2010 cost reduction initiatives.  These costs were deferred as a result of the approved modified settlement agreement of APCo’s West Virginia base rate case in March 2011.
 
These decreases were partially offset by:
 
·
A $41 million increase due to the first quarter 2011 write-off of a portion of the West Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC.
 
·
A $25 million increase due to the second quarter 2010 deferral of 2009 storm costs as allowed by the Virginia SCC.
 
·
A $15 million increase in storm-related expenses.
 
·
An $8 million increase in transmission expenses primarily due to the Transmission Agreement modification effective November 2010.
 ·
Depreciation and Amortization expenses decreased $14 million primarily due to the expiration of E&R amortization of deferred carrying costs in Virginia, partially offset by an increased depreciation base resulting from environmental upgrades at the Amos Plant.
 ·
Taxes Other Than Income Taxes decreased $3 million primarily due to recording a West Virginia franchise tax audit settlement and additional employer payroll taxes incurred related to the cost reduction initiatives in the second quarter of 2010.
 ·
Carrying Costs Income decreased $6 million primarily due to decreased environmental deferrals in Virginia.
 ·
Income Tax Expense increased $10 million primarily due to an increase in pretax book income.
 
FINANCIAL CONDITION

LIQUIDITY

APCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  APCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 227 for additional discussion of liquidity.

Credit Ratings

APCo’s access to capital markets may depend on its credit ratings.  In addition, a credit rating downgrade of APCo by one of the rating agencies could increase APCo’s borrowing costs.  Failure to maintain investment grade ratings may constrain APCo’s ability to participate in the Utility Money Pool or the amount of APCo’s receivables securitized by AEP Credit.  Counterparty concerns about APCo’s credit quality could subject APCo to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.
 
87

 

CASH FLOW

Cash flows for the six months ended June 30, 2011 and 2010 were as follows:

 
 
2011
   
2010
 
 
 
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
  $ 951     $ 2,006  
Net Cash Flows from Operating Activities
    386,198       252,172  
Net Cash Flows Used for Investing Activities
    (346,080 )     (252,171 )
Net Cash Flows Used for Financing Activities
    (39,437 )     (181 )
Net Increase (Decrease) in Cash and Cash Equivalents
    681       (180 )
Cash and Cash Equivalents at End of Period
  $ 1,632     $ 1,826  
 
Operating Activities

Net Cash Flows from Operating Activities were $386 million in 2011.  APCo produced Net Income of $71 million during the period and had noncash expense items of $137 million for Depreciation and Amortization and $128 million for Deferred Income Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $85 million inflow from Accounts Receivable, Net was primarily due to a decrease in accrued unbilled revenues due to usual seasonal fluctuations and timing of settlements of receivables from affiliated companies.  The $85 million inflow from Fuel, Materials and Supplies was primarily due to a reduction in fuel.  The $63 million outflow from Accounts Payable was primarily due to decreased energy purchases and reduced operation and maintenance expenses.  The $56 million outflow from Accrued Taxes, Net was primarily due to decreased accruals related to federal income taxes.

Net Cash Flows from Operating Activities were $252 million in 2010.  APCo produced Net Income of $51 million during the period and had noncash expense items of $151 million for Depreciation and Amortization and $32 million for Deferred Income Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $100 million outflow from Accounts Payable was primarily due to payments for storm costs accrued in fourth quarter of 2009 and decreased purchases of energy from the system pool.  The $76 million inflow from Accounts Receivable, Net was primarily due to a decrease in accrued revenues due to usual seasonal fluctuations and timing of settlements of receivables from affiliated companies.  The $69 million inflow from Fuel, Materials and Supplies was primarily due to a reduction in fuel inventory and a decrease in the average cost of coal per ton.  The $39 million outflow from Accrued Taxes, Net was primarily due to decreased accruals related to federal income taxes.  The $32 million outflow from Fuel Over/Under-Recovery, Net was primarily due to a net under-recovery of fuel costs in West Virginia.

Investing Activities

Net Cash Flows Used for Investing Activities during 2011 and 2010 were $346 million and $252 million, respectively.  Construction Expenditures of $191 million and $255 million in 2011 and 2010, respectively, were primarily for environmental upgrades, as well as projects to improve generation and service reliability for transmission and distribution.  Environmental upgrades include FGD projects at the Amos Plant.  During 2011, APCo had a net increase of $163 million in loans to the Utility Money Pool.
 
Financing Activities

Net Cash Flows Used for Financing Activities were $39 million in 2011.  APCo issued $350 million of Senior Unsecured Notes and $295 million of Pollution Control Bonds, partially offset by the retirement of $250 million of Senior Unsecured Notes and $230 million of Pollution Control Bonds.  APCo had a net decrease of $128 million in borrowings from the Utility Money Pool.  In addition, APCo paid $68 million in common stock dividends.
 
88

 

Net Cash Flows Used for Financing Activities were $181 thousand in 2010.  APCo issued $300 million of Senior Unsecured Notes and $68 million of Pollution Control Bonds, partially offset by the retirement of $150 million of Senior Unsecured Notes, $100 million of Notes Payable – Affiliated and $50 million of Pollution Control Bonds. APCo had a net increase of $17 million in borrowings from the Utility Money Pool.  In addition, APCo paid $78 million in common stock dividends.

Long-term debt issuances, retirements and principal payments made during the first six months of 2011 were:

Issuances
 
 
 
 
 
 
 
 
 
 
 
Principal
 
Interest
 
Due
 
Type of Debt
 
Amount
 
Rate
 
Date
 
 
 
(in thousands)
 
(%)
 
 
 
Senior Unsecured Notes
 
$
 350,000 
 
4.60 
 
2021 
 
Pollution Control Bonds
 
 
 65,350 
 
2.00 
 
2012 
 
Pollution Control Bonds
 
 
 75,000 
(a)
Variable
 
2036 
 
Pollution Control Bonds
 
 
 50,275 
(a)
Variable
 
2036 
 
Pollution Control Bonds
 
 
 54,375 
(a)
Variable
 
2042 
 
Pollution Control Bonds
 
 
 50,000 
(a)
Variable
 
2042 

(a)  
These pollution control bonds are subject to redemption earlier than the maturity date.  Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on APCo’s Condensed Consolidated Balance Sheets.

Retirements and Principal Payments
 
 
 
 
 
 
 
 
 
 
Principal
 
Interest
 
Due
 
Type of Debt
 
Amount Paid
 
Rate
 
Date
 
 
 
(in thousands)
 
(%)
 
 
 
Pollution Control Bonds
 
$
 75,000 
 
Variable
 
2036 
 
Pollution Control Bonds
 
 
 50,275 
 
Variable
 
2036 
 
Pollution Control Bonds
 
 
 54,375 
 
Variable
 
2042 
 
Pollution Control Bonds
 
 
 50,000 
 
Variable
 
2042 
 
Senior Unsecured Notes
 
 
 250,000 
 
5.55 
 
2011 
 
Land Note
 
 
 11 
 
13.718 
 
2026 

CONTRACTUAL OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2010 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of market risk.

 
89

 


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 
For the Three and Six Months Ended June 30, 2011 and 2010
 
(in thousands)
 
(Unaudited)
 
 
 
 
 
 
 
Three Months Ended
   
Six Months Ended
 
 
 
2011
   
2010
   
2011
   
2010
 
REVENUES
 
 
   
 
   
 
   
 
 
Electric Generation, Transmission and Distribution
  $ 666,785     $ 633,140     $ 1,417,797     $ 1,479,130  
Sales to AEP Affiliates
    82,531       67,365       161,222       146,136  
Other Revenues
    2,129       2,769       4,246       4,631  
TOTAL REVENUES
    751,445       703,274       1,583,265       1,629,897  
 
                               
EXPENSES
                               
Fuel and Other Consumables Used for Electric Generation
    184,698       169,616       365,279       350,256  
Purchased Electricity for Resale
    69,127       56,936       138,345       120,619  
Purchased Electricity from AEP Affiliates
    183,661       179,607       407,850       447,109  
Other Operation
    74,617       170,907       187,893       260,947  
Maintenance
    57,163       14,060       89,456       77,170  
Depreciation and Amortization
    67,644       73,160       136,743       150,590  
Taxes Other Than Income Taxes
    25,968       29,955       53,071       56,235  
TOTAL EXPENSES
    662,878       694,241       1,378,637       1,462,926  
 
                               
OPERATING INCOME
    88,567       9,033       204,628       166,971  
 
                               
Other Income (Expense):
                               
Interest Income
    762       662       1,082       953  
Carrying Costs Income
    6,542       10,298       9,981       16,062  
Allowance for Equity Funds Used During Construction
    1,212       128       2,095       1,291  
Interest Expense
    (53,188 )     (51,831 )     (106,127 )     (103,558 )
 
                               
INCOME (LOSS) BEFORE INCOME TAX EXPENSE
                               
(CREDIT)
    43,895       (31,710 )     111,659       81,719  
 
                               
Income Tax Expense (Credit)
    12,268       (12,091 )     41,052       31,056  
 
                               
NET INCOME (LOSS)
    31,627       (19,619 )     70,607       50,663  
 
                               
Preferred Stock Dividend Requirements Including Capital
                               
Stock Expense
    200       225       400       450  
 
                               
EARNINGS (LOSS) ATTRIBUTABLE TO COMMON
                               
STOCK
  $ 31,427     $ (19,844 )   $ 70,207     $ 50,213  
 
 
The common stock of APCo is wholly-owned by AEP.
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.
 


 
90

 


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
Total
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – DECEMBER 31, 2009
 
$
 260,458 
 
$
 1,475,393 
 
$
 1,085,980 
 
$
 (50,254)
 
$
 2,771,577 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (78,000)
 
 
 
 
 
 (78,000)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (399)
 
 
 
 
 
 (399)
Capital Stock Expense
 
 
 
 
 
 52 
 
 
 (51)
 
 
 
 
 
 1 
SUBTOTAL – COMMON
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 2,693,179 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $1,369
 
 
 
 
 
 
 
 
 
 
 
 (2,542)
 
 
 (2,542)
 
 
Amortization of Pension and OPEB Deferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Costs, Net of Tax of $1,124
 
 
 
 
 
 
 
 
 
 
 
 2,087 
 
 
 2,087 
NET INCOME
 
 
 
 
 
 
 
 
 50,663 
 
 
 
 
 
 50,663 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 50,208 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – JUNE 30, 2010
 
$
 260,458 
 
$
 1,475,445 
 
$
 1,058,193 
 
$
 (50,709)
 
$
 2,743,387 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – DECEMBER 31, 2010
 
$
 260,458 
 
$
 1,475,496 
 
$
 1,133,748 
 
$
 (48,023)
 
$
 2,821,679 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (67,500)
 
 
 
 
 
 (67,500)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (400)
 
 
 
 
 
 (400)
Gain on Reacquired Preferred Stock
 
 
 
 
 
 3 
 
 
 
 
 
 
 
 
 3 
SUBTOTAL – COMMON
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 2,753,782 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $652
 
 
 
 
 
 
 
 
 
 
 
 1,211 
 
 
 1,211 
 
 
Amortization of Pension and OPEB Deferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Costs, Net of Tax of $837
 
 
 
 
 
 
 
 
 
 
 
 1,554 
 
 
 1,554 
NET INCOME
 
 
 
 
 
 
 
 
 70,607 
 
 
 
 
 
 70,607 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 73,372 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – JUNE 30, 2011
 
$
 260,458 
 
$
 1,475,499 
 
$
 1,136,455 
 
$
 (45,258)
 
$
 2,827,154 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.


 
91

 


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)
 
 
 
2011 
 
2010 
CURRENT ASSETS
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 1,632 
 
$
 951 
Advances to Affiliates
 
 
 162,787 
 
 
 - 
Accounts Receivable:
 
 
 
 
 
 
 
Customers
 
 
 179,695 
 
 
 166,878 
 
Affiliated Companies
 
 
 107,225 
 
 
 145,972 
 
Accrued Unbilled Revenues
 
 
 52,705 
 
 
 108,210 
 
Miscellaneous
 
 
 2,961 
 
 
 3,090 
 
Allowance for Uncollectible Accounts
 
 
 (6,839)
 
 
 (6,667)
 
 
Total Accounts Receivable
 
 
 335,747 
 
 
 417,483 
Fuel
 
 
 142,478 
 
 
 230,697 
Materials and Supplies
 
 
 92,140 
 
 
 89,370 
Risk Management Assets
 
 
 31,814 
 
 
 53,242 
Accrued Tax Benefits
 
 
 127,008 
 
 
 104,435 
Regulatory Asset for Under-Recovered Fuel Costs
 
 
 19,287 
 
 
 18,300 
Prepayments and Other Current Assets
 
 
 29,672 
 
 
 35,811 
TOTAL CURRENT ASSETS
 
 
 942,565 
 
 
 950,289 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
Generation
 
 
 5,103,051 
 
 
 4,736,150 
 
Transmission
 
 
 1,889,841 
 
 
 1,852,415 
 
Distribution
 
 
 2,779,289 
 
 
 2,740,752 
Other Property, Plant and Equipment
 
 
 351,076 
 
 
 348,013 
Construction Work in Progress
 
 
 241,339 
 
 
 562,280 
Total Property, Plant and Equipment
 
 
 10,364,596 
 
 
 10,239,610 
Accumulated Depreciation and Amortization
 
 
 2,927,174 
 
 
 2,843,087 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
 
 
 7,437,422 
 
 
 7,396,523 
 
 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
Regulatory Assets
 
 
 1,506,936 
 
 
 1,486,625 
Long-term Risk Management Assets
 
 
 32,146 
 
 
 38,420 
Deferred Charges and Other Noncurrent Assets
 
 
 119,618 
 
 
 125,296 
TOTAL OTHER NONCURRENT ASSETS
 
 
 1,658,700 
 
 
 1,650,341 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 10,038,687 
 
$
 9,997,153 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

 
92

 


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, 2011 and December 31, 2010
(Unaudited)
 
 
 
2011 
 
2010 
 
 
 
(in thousands)
CURRENT LIABILITIES
 
 
 
 
 
 
Advances from Affiliates
 
$
 - 
 
$
 128,331 
Accounts Payable:
 
 
 
 
 
 
 
General
 
 
 173,512 
 
 
 223,144 
 
Affiliated Companies
 
 
 134,238 
 
 
 166,884 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 229,673 
 
 
 479,672 
Risk Management Liabilities
 
 
 18,502 
 
 
 27,993 
Customer Deposits
 
 
 60,488 
 
 
 58,451 
Deferred Income Taxes
 
 
 36,934 
 
 
 44,180 
Accrued Taxes
 
 
 70,043 
 
 
 75,619 
Accrued Interest
 
 
 59,130 
 
 
 57,871 
Other Current Liabilities
 
 
 96,315 
 
 
 93,286 
TOTAL CURRENT LIABILITIES
 
 
 878,835 
 
 
 1,355,431 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 3,496,213 
 
 
 3,081,469 
Long-term Risk Management Liabilities
 
 
 10,328 
 
 
 10,873 
Deferred Income Taxes
 
 
 1,756,479 
 
 
 1,642,072 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 566,314 
 
 
 562,381 
Employee Benefits and Pension Obligations
 
 
 284,578 
 
 
 306,460 
Deferred Credits and Other Noncurrent Liabilities
 
 
 201,050 
 
 
 199,041 
TOTAL NONCURRENT LIABILITIES
 
 
 6,314,962 
 
 
 5,802,296 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 7,193,797 
 
 
 7,157,727 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
 
 
 17,736 
 
 
 17,747 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
Commitments and Contingencies (Note 4)
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
 
 
Common Stock – No Par Value:
 
 
 
 
 
 
 
Authorized – 30,000,000 Shares
 
 
 
 
 
 
 
Outstanding  – 13,499,500 Shares
 
 
 260,458 
 
 
 260,458 
Paid-in Capital
 
 
 1,475,499 
 
 
 1,475,496 
Retained Earnings
 
 
 1,136,455 
 
 
 1,133,748 
Accumulated Other Comprehensive Income (Loss)
 
 
 (45,258)
 
 
 (48,023)
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 2,827,154 
 
 
 2,821,679 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
 10,038,687 
 
$
 9,997,153 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

 
93

 


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
2011 
 
2010 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net Income
 
$
 70,607 
 
$
 50,663 
Adjustments to Reconcile Net Income to Net Cash Flows from
 
 
 
 
 
 
 
Operating Activities:
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 136,743 
 
 
 150,590 
 
 
Deferred Income Taxes
 
 
 127,525 
 
 
 32,037 
 
 
Carrying Costs Income
 
 
 (9,981)
 
 
 (16,062)
 
 
Allowance for Equity Funds Used During Construction
 
 
 (2,095)
 
 
 (1,291)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 7,343 
 
 
 9,975 
 
 
Fuel Over/Under-Recovery, Net
 
 
 (21,132)
 
 
 (32,329)
 
 
Change in Other Noncurrent Assets
 
 
 11,361 
 
 
 42,141 
 
 
Change in Other Noncurrent Liabilities
 
 
 5,239 
 
 
 (5,225)
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 84,748 
 
 
 75,903 
 
 
 
Fuel, Materials and Supplies
 
 
 85,449 
 
 
 69,469 
 
 
 
Accounts Payable
 
 
 (62,795)
 
 
 (100,171)
 
 
 
Accrued Taxes, Net
 
 
 (56,411)
 
 
 (38,806)
 
 
 
Other Current Assets
 
 
 6,281 
 
 
 5,421 
 
 
 
Other Current Liabilities
 
 
 3,316 
 
 
 9,857 
Net Cash Flows from Operating Activities
 
 
 386,198 
 
 
 252,172 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
Construction Expenditures
 
 
 (191,125)
 
 
 (254,663)
Change in Advances to Affiliates, Net
 
 
 (162,787)
 
 
 - 
Other Investing Activities
 
 
 7,832 
 
 
 2,492 
Net Cash Flows Used for Investing Activities
 
 
 (346,080)
 
 
 (252,171)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
 
 640,164 
 
 
 363,913 
Change in Advances from Affiliates, Net
 
 
 (128,331)
 
 
 17,327 
Retirement of Long-term Debt – Nonaffiliated
 
 
 (479,661)
 
 
 (200,009)
Retirement of Long-term Debt – Affiliated
 
 
 - 
 
 
 (100,000)
Retirement of Cumulative Preferred Stock
 
 
 (8)
 
 
 (4)
Principal Payments for Capital Lease Obligations
 
 
 (3,720)
 
 
 (3,600)
Dividends Paid on Common Stock
 
 
 (67,500)
 
 
 (78,000)
Dividends Paid on Cumulative Preferred Stock
 
 
 (400)
 
 
 (399)
Other Financing Activities
 
 
 19 
 
 
 591 
Net Cash Flows Used for Financing Activities
 
 
 (39,437)
 
 
 (181)
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 681 
 
 
 (180)
Cash and Cash Equivalents at Beginning of Period
 
 
 951 
 
 
 2,006 
Cash and Cash Equivalents at End of Period
 
$
 1,632 
 
$
 1,826 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 100,127 
 
$
 103,271 
Net Cash Paid (Received) for Income Taxes
 
 
 (33,371)
 
 
 30,259 
Noncash Acquisitions Under Capital Leases
 
 
 565 
 
 
 22,344 
Government Grants Included in Accounts Receivable at June 30,
 
 
 4,061 
 
 
 - 
Construction Expenditures Included in Current Liabilities at June 30,
 
 
 52,421 
 
 
 42,890 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

 
94

 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to APCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to APCo.  The footnotes begin on page 162.

 
Footnote
Reference
   
Significant Accounting Matters
Note 1
   
New Accounting Pronouncements
Note 2
   
Rate Matters
Note 3
   
Commitments, Guarantees and Contingencies
Note 4
   
Benefit Plans
Note 6
   
Business Segments
Note 7
   
Derivatives and Hedging
Note 8
   
Fair Value Measurements
Note 9
   
Income Taxes
Note 10
   
Financing Activities
Note 11
   
Cost Reduction Initiatives
Note 12


 
95

 










COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES


 
96

 

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

EXECUTIVE OVERVIEW

Ohio Customer Choice

In CSPCo’s service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service.  As a result, in comparison to the second quarter of 2010 and the first six months of 2010, CSPCo lost approximately $22 million and $40 million, respectively, of generation related gross margin.  Management anticipates recovery of a portion of lost margins through off-system sales, including PJM capacity revenues.

Regulatory Activity

2009 – 2011 ESPs

In April 2011, the Supreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact through a remand proceeding.  Pursuant to a May 2011 PUCO order, CSPCo implemented rates subject to refund.  Certain intervenors proposed adjustments that included a reduction of deferred FAC and other regulatory assets for the period prior to June 2011 of up to $298 million, excluding carrying costs, which CSPCo believes is without merit and violates the Supreme Court of Ohio decision.  The proposed adjustments also included refunds and rate reductions of related revenues beginning in June 2011 of up to $72 million.  See “Ohio Electric Security Plan Filings” section of Note 3.

January 2012 – May 2014 ESP

In January 2011, CSPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation.  The rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The SSO presents redesigned generation rates by customer class.  Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013.  Under the new ESP, management estimates CSPCo will have base generation revenue increases, excluding riders, of $17 million for 2012 and $46 million for 2013.  The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESPs could impact the outcome of the January 2012-May 2014 ESP, though the nature and extent of that impact is not presently known.  See “Ohio Electric Security Plan Filings” section of Note 3.

Ohio Distribution Base Rate Case

In February 2011, CSPCo filed with the PUCO for annual increases in distribution rates of $34 million.  The requested increase is based upon an 11.15% return on common equity to be effective January 2012.  In addition to the annual increase, CSPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $216 million, including approximately $102 million of unrecognized equity carrying costs.  These assets and unrecognized carrying costs would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013.  The actual balance of these distribution regulatory assets as of June 30, 2011 was $100 million, excluding $61 million of unrecognized equity carrying costs.  If CSPCo is not ultimately permitted to fully recover its deferrals, it would reduce future net income and cash flows and impact financial condition.  See “2011 Ohio Distribution Base Rate Case” section of Note 3.
 
97

 
 
Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo.  Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company.  In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo.  CSPCo and OPCo requested the reorganization transaction be effective in October 2011.  In July 2011, the FERC issued an order approving the proposed merger.  A decision is pending from the PUCO.  See “Proposed CSPCo and OPCo Merger” section of Note 3.

Litigation and Environmental Issues

In the ordinary course of business, CSPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 162.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 227 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
KWH Sales/Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summary of KWH Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 1,594 
 
 
 1,567 
 
 
 3,722 
 
 
 3,793 
 
Commercial
 
 2,118 
 
 
 2,213 
 
 
 4,113 
 
 
 4,214 
 
Industrial
 
 1,359 
 
 
 1,157 
 
 
 2,629 
 
 
 2,268 
 
Miscellaneous
 
 13 
 
 
 14 
 
 
 28 
 
 
 27 
Total Retail
 
 5,084 
 
 
 4,951 
 
 
 10,492 
 
 
 10,302 
 
 
 
 
 
 
 
 
 
 
 
 
Wholesale
 
 1,178 
 
 
 637 
 
 
 2,041 
 
 
 1,356 
 
 
 
 
 
 
 
 
 
 
 
 
Total KWHs
 
 6,262 
 
 
 5,588 
 
 
 12,533 
 
 
 11,658 

 
98

 
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.

Summary of Heating and Cooling Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
June 30,
 
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in degree days)
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 122 
 
 
 70 
 
 
 2,050 
 
 
 2,035 
Normal - Heating (b)
 
 164 
 
 
 165 
 
 
 1,947 
 
 
 1,950 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 369 
 
 
 430 
 
 
 370 
 
 
 430 
Normal - Cooling (b)
 
 299 
 
 
 293 
 
 
 302 
 
 
 296 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Eastern 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.

 
99

 
Second Quarter of 2011 Compared to Second Quarter of 2010
 
 
 
 
 
Reconciliation of Second Quarter of 2010 to Second Quarter of 2011
 
Net Income
 
(in millions)
 
 
 
 
 
Second Quarter of 2010
  $ 52  
 
       
Changes in Gross Margin:
       
Retail Margins
    (30 )
Off-system Sales
    19  
Transmission Revenues
    1  
Total Change in Gross Margin
    (10 )
 
       
Changes in Expenses and Other:
       
Other Operation and Maintenance
    31  
Other Income
    1  
Interest Expense
    1  
Total Change in Expenses and Other
    33  
 
       
Income Tax Expense
    (8 )
 
       
Second Quarter of 2011
  $ 67  

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

·
Retail Margins decreased $30 million due to the following:
 
·
A $22 million decrease attributable to customers switching to alternative competitive retail electric service (CRES) providers.
 
·
A $6 million decrease in residential and industrial margins primarily due to a change in the customer mix resulting in lower realizations.
 
·
A $5 million decrease in weather-related usage due to a 14% decrease in cooling degree days.
 
These decreases were partially offset by:
 
·
A $7 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs.  This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
·
Margins from Off-system Sales increased $19 million primarily due to an increase in PJM capacity revenues and higher physical sales volumes.

 
100

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

·
Other Operation and Maintenance expenses decreased $31 million primarily due to:
 
·
A $31 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
 
·
An $8 million decrease in transmission expense primarily due to the Transmission Agreement modification effective November 2010, a portion of which is included in the Ohio Transmission Cost Recovery Rider.
 
These decreases were partially offset by:
 
·
A $7 million increase in expenses due to the implementation of PUCO approved EE/PDR programs.  This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
 
·
A $7 million increase in plant maintenance expenses primarily related to work performed at the Stuart, Waterford and Conesville plants.
·
Income Tax Expense increased $8 million primarily due to an increase in pretax book income.

 
101

 
Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010
 
 
 
 
 
 
Reconciliation of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2011
Net Income
(in millions)
 
 
 
 
 
Six Months Ended June 30, 2010
 
$
 104 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
Retail Margins
 
 
 (20)
 
Off-system Sales
 
 
 32 
 
Transmission Revenues
 
 
 1 
 
Other Revenues
 
 
 (1)
 
Total Change in Gross Margin
 
 
 12 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
Other Operation and Maintenance
 
 
 32 
 
Depreciation and Amortization
 
 
 (4)
 
Taxes Other Than Income Taxes
 
 
 (3)
 
Other Income
 
 
 2 
 
Interest Expense
 
 
 3 
 
Total Change in Expenses and Other
 
 
 30 
 
 
 
 
 
 
Income Tax Expense
 
 
 (14)
 
 
 
 
 
 
Six Months Ended June 30, 2011
 
$
 132 
 

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

  ·
Retail Margins decreased $20 million primarily due to:
 
·
A $40 million decrease attributable to customers switching to alternative competitive retail electric service (CRES) providers.
 
·
A $6 million decrease in weather-related usage due to a 14% decrease in cooling degree days.
 
·
A $3 million decrease in capacity settlements under the Interconnection Agreement.
 
These decreases were partially offset by:
 
·
A $19 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs.  This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
 
·
A $10 million increase associated with the final 2009 SEET order.
·
Margins from Off-system Sales increased $32 million primarily due to an increase in PJM capacity revenues and higher physical sales volumes.

 
102

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

  ·
Other Operation and Maintenance expenses decreased $32 million primarily due to:
 
·
A $31 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
 
 
·
A $15 million decrease in transmission expense primarily due to the Transmission Agreement modification effective November 2010, a portion of which is included in the Ohio Transmission Cost Recovery Rider.
 
 
·
A $15 million decrease in recoverable PJM expenses.
 
 
These decreases were partially offset by:
 
 
·
A $19 million increase in expenses due to the implementation of PUCO approved EE/PDR programs.  This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
 
 
·
A $14 million increase in plant maintenance and operation expenses primarily related to work performed at the Stuart, Waterford and Conesville plants.
 
  ·
Depreciation and Amortization increased $4 million as a result of recognizing deferred debt and equity carrying charges on deferred fuel as permitted under the final 2009 SEET order.
  ·
Taxes Other Than Income Taxes increased $3 million primarily due to an increase in property taxes.
  ·
Interest Expense decreased $3 million primarily as a result of a long-term debt retirement in December 2010.
  ·
Income Tax Expense increased $14 million primarily due to an increase in pretax book income.
 
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of market risk.

 
103

 


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
Three Months Ended
 
Six Months Ended
 
 
2011 
 
2010 
 
2011 
 
2010 
REVENUES
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission and Distribution
 
$
 482,655 
 
$
 503,270 
 
$
 986,026 
 
$
 1,004,289 
Sales to AEP Affiliates
 
 
 38,421 
 
 
 20,090 
 
 
 79,146 
 
 
 35,922 
Other Revenues
 
 
 383 
 
 
 744 
 
 
 889 
 
 
 1,332 
TOTAL REVENUES
 
 
 521,459 
 
 
 524,104 
 
 
 1,066,061 
 
 
 1,041,543 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EXPENSES
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
 
 93,760 
 
 
 105,290 
 
 
 206,673 
 
 
 219,731 
Purchased Electricity for Resale
 
 
 24,885 
 
 
 20,138 
 
 
 48,402 
 
 
 39,783 
Purchased Electricity from AEP Affiliates
 
 
 105,369 
 
 
 91,287 
 
 
 206,980 
 
 
 190,086 
Other Operation
 
 
 65,113 
 
 
 103,229 
 
 
 136,180 
 
 
 180,555 
Maintenance
 
 
 32,423 
 
 
 25,114 
 
 
 61,523 
 
 
 49,397 
Depreciation and Amortization
 
 
 37,531 
 
 
 37,602 
 
 
 78,957 
 
 
 75,089 
Taxes Other Than Income Taxes
 
 
 44,128 
 
 
 44,294 
 
 
 94,277 
 
 
 91,351 
TOTAL EXPENSES
 
 
 403,209 
 
 
 426,954 
 
 
 832,992 
 
 
 845,992 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
 
 118,250 
 
 
 97,150 
 
 
 233,069 
 
 
 195,551 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 183 
 
 
 167 
 
 
 350 
 
 
 309 
Carrying Costs Income
 
 
 2,268 
 
 
 1,963 
 
 
 5,922 
 
 
 4,184 
Allowance for Equity Funds Used During Construction
 
 
 547 
 
 
 314 
 
 
 1,318 
 
 
 1,235 
Interest Expense
 
 
 (20,201)
 
 
 (21,091)
 
 
 (39,949)
 
 
 (42,875)
 
 
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
 
 101,047 
 
 
 78,503 
 
 
 200,710 
 
 
 158,404 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 34,519 
 
 
 26,387 
 
 
 68,624 
 
 
 54,638 
 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME
 
 
 66,528 
 
 
 52,116 
 
 
 132,086 
 
 
 103,766 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital Stock Expense
 
 
 25 
 
 
 40 
 
 
 50 
 
 
 79 
 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
 
$
 66,503 
 
$
 52,076 
 
$
 132,036 
 
$
 103,687 
 
 
 
 
 
 
 
 
 
 
 
 
 
The common stock of CSPCo is wholly-owned by AEP.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.


 
104

 


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
Total
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – DECEMBER 31, 2009
 
$
 41,026 
 
$
 580,663 
 
$
 788,139 
 
$
 (49,993)
 
$
 1,359,835 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (52,500)
 
 
 
 
 
 (52,500)
Capital Stock Expense
 
 
 
 
 
 79 
 
 
 (79)
 
 
 
 
 
 - 
SUBTOTAL – COMMON
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,307,335 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $232
 
 
 
 
 
 
 
 
 
 
 
 (431)
 
 
 (431)
 
 
Amortization of Pension and OPEB Deferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Costs, Net of Tax of $667
 
 
 
 
 
 
 
 
 
 
 
 1,238 
 
 
 1,238 
NET INCOME
 
 
 
 
 
 
 
 
 103,766 
 
 
 
 
 
 103,766 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 104,573 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – JUNE 30, 2010
 
$
 41,026 
 
$
 580,742 
 
$
 839,326 
 
$
 (49,186)
 
$
 1,411,908 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – DECEMBER 31, 2010
 
$
 41,026 
 
$
 580,812 
 
$
 915,713 
 
$
 (51,336)
 
$
 1,486,215 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (125,000)
 
 
 
 
 
 (125,000)
Capital Stock Expense
 
 
 
 
 
 50 
 
 
 (50)
 
 
 
 
 
 - 
SUBTOTAL – COMMON
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,361,215 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $265
 
 
 
 
 
 
 
 
 
 
 
 492 
 
 
 492 
 
 
Amortization of Pension and OPEB Deferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Costs, Net of Tax of $688
 
 
 
 
 
 
 
 
 
 
 
 1,278 
 
 
 1,278 
NET INCOME
 
 
 
 
 
 
 
 
 132,086 
 
 
 
 
 
 132,086 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 133,856 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – JUNE 30, 2011
 
$
 41,026 
 
$
 580,862 
 
$
 922,749 
 
$
 (49,566)
 
$
 1,495,071 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.


 
105

 


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)
 
 
 
2011 
 
2010 
CURRENT ASSETS
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 1,295 
 
$
 509 
Other Cash Deposits
 
 
 2,260 
 
 
 2,260 
Advances to Affiliates
 
 
 71,323 
 
 
 54,202 
Accounts Receivable:
 
 
 
 
 
 
 
Customers
 
 
 51,282 
 
 
 50,187 
 
Affiliated Companies
 
 
 42,371 
 
 
 66,788 
 
Accrued Unbilled Revenues
 
 
 5,657 
 
 
 32,821 
 
Miscellaneous
 
 
 5,736 
 
 
 14,374 
 
Allowance for Uncollectible Accounts
 
 
 (1,638)
 
 
 (1,584)
 
 
Total Accounts Receivable
 
 
 103,408 
 
 
 162,586 
Fuel
 
 
 59,842 
 
 
 72,882 
Materials and Supplies
 
 
 41,409 
 
 
 42,033 
Emission Allowances
 
 
 25,272 
 
 
 28,486 
Risk Management Assets
 
 
 18,351 
 
 
 23,774 
Accrued Tax Benefits
 
 
 22,014 
 
 
 8,797 
Regulatory Asset for Under-Recovered Fuel Costs
 
 
 26,672 
 
 
 - 
Margin Deposits
 
 
 12,986 
 
 
 14,762 
Prepayments and Other Current Assets
 
 
 8,104 
 
 
 26,864 
TOTAL CURRENT ASSETS
 
 
 392,936 
 
 
 437,155 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
Generation
 
 
 2,725,375 
 
 
 2,686,294 
 
Transmission
 
 
 676,863 
 
 
 662,312 
 
Distribution
 
 
 1,820,031 
 
 
 1,796,023 
Other Property, Plant and Equipment
 
 
 204,858 
 
 
 203,593 
Construction Work in Progress
 
 
 149,955 
 
 
 172,793 
Total Property, Plant and Equipment
 
 
 5,577,082 
 
 
 5,521,015 
Accumulated Depreciation and Amortization
 
 
 1,989,614 
 
 
 1,927,112 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
 
 
 3,587,468 
 
 
 3,593,903 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
Regulatory Assets
 
 
 313,651 
 
 
 298,111 
Long-term Risk Management Assets
 
 
 18,578 
 
 
 22,089 
Deferred Charges and Other Noncurrent Assets
 
 
 98,461 
 
 
 152,932 
TOTAL OTHER NONCURRENT ASSETS
 
 
 430,690 
 
 
 473,132 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 4,411,094 
 
$
 4,504,190 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

 
106

 


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY
June 30, 2011 and December 31, 2010
(Unaudited)
 
 
 
2011 
 
2010 
 
 
 
(in thousands)
CURRENT LIABILITIES
 
 
 
 
 
 
Accounts Payable:
 
 
 
 
 
 
 
General
 
$
 80,339 
 
$
 98,925 
 
Affiliated Companies
 
 
 70,165 
 
 
 78,617 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 194,500 
 
 
 - 
Risk Management Liabilities
 
 
 10,668 
 
 
 15,967 
Customer Deposits
 
 
 30,652 
 
 
 29,441 
Accrued Taxes
 
 
 137,197 
 
 
 226,572 
Accrued Interest
 
 
 22,580 
 
 
 22,533 
Other Current Liabilities
 
 
 88,576 
 
 
 111,868 
TOTAL CURRENT LIABILITIES
 
 
 634,677 
 
 
 583,923 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 1,244,469 
 
 
 1,438,830 
Long-term Risk Management Liabilities
 
 
 5,964 
 
 
 6,223 
Deferred Income Taxes
 
 
 642,748 
 
 
 604,828 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 168,346 
 
 
 163,888 
Employee Benefits and Pension Obligations
 
 
 133,149 
 
 
 136,643 
Deferred Credits and Other Noncurrent Liabilities
 
 
 86,670 
 
 
 83,640 
TOTAL NONCURRENT LIABILITIES
 
 
 2,281,346 
 
 
 2,434,052 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 2,916,023 
 
 
 3,017,975 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
Commitments and Contingencies (Note 4)
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
 
 
Common Stock – No Par Value:
 
 
 
 
 
 
 
Authorized – 24,000,000 Shares
 
 
 
 
 
 
 
Outstanding  – 16,410,426 Shares
 
 
 41,026 
 
 
 41,026 
Paid-in Capital
 
 
 580,862 
 
 
 580,812 
Retained Earnings
 
 
 922,749 
 
 
 915,713 
Accumulated Other Comprehensive Income (Loss)
 
 
 (49,566)
 
 
 (51,336)
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 1,495,071 
 
 
 1,486,215 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY
 
$
 4,411,094 
 
$
 4,504,190 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.


 
107

 


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
2011 
 
2010 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net Income
 
$
 132,086 
 
$
 103,766 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 78,957 
 
 
 75,089 
 
 
Deferred Income Taxes
 
 
 58,594 
 
 
 19,833 
 
 
Allowance for Equity Funds Used During Construction
 
 
 (1,318)
 
 
 (1,235)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 4,206 
 
 
 1,466 
 
 
Property Taxes
 
 
 57,078 
 
 
 48,526 
 
 
Fuel Over/Under-Recovery, Net
 
 
 (12,072)
 
 
 32,120 
 
 
Change in Other Noncurrent Assets
 
 
 (24,713)
 
 
 (17,051)
 
 
Change in Other Noncurrent Liabilities
 
 
 8,023 
 
 
 (2,458)
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 51,840 
 
 
 (17,458)
 
 
 
Fuel, Materials and Supplies
 
 
 16,424 
 
 
 (3,512)
 
 
 
Accounts Payable
 
 
 (19,262)
 
 
 (12,744)
 
 
 
Accrued Taxes, Net
 
 
 (107,239)
 
 
 (89,647)
 
 
 
Other Current Assets
 
 
 5,200 
 
 
 8,582 
 
 
 
Other Current Liabilities
 
 
 (34,703)
 
 
 12,262 
Net Cash Flows from Operating Activities
 
 
 213,101 
 
 
 157,539 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
Construction Expenditures
 
 
 (92,578)
 
 
 (84,208)
Change in Other Cash Deposits
 
 
 - 
 
 
 10,289 
Change in Advances to Affiliates, Net
 
 
 (17,121)
 
 
 (57,069)
Acquisitions of Assets
 
 
 (527)
 
 
 (463)
Proceeds from Sales of Assets
 
 
 6,280 
 
 
 3,410 
Other Investing Activities
 
 
 18,286 
 
 
 - 
Net Cash Flows Used for Investing Activities
 
 
 (85,660)
 
 
 (128,041)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
 
 - 
 
 
 149,443 
Change in Advances from Affiliates, Net
 
 
 - 
 
 
 (24,202)
Retirement of Long-term Debt – Affiliated
 
 
 - 
 
 
 (100,000)
Principal Payments for Capital Lease Obligations
 
 
 (1,674)
 
 
 (2,237)
Dividends Paid on Common Stock
 
 
 (125,000)
 
 
 (52,500)
Other Financing Activities
 
 
 19 
 
 
 95 
Net Cash Flows Used for Financing Activities
 
 
 (126,655)
 
 
 (29,401)
 
 
 
 
 
 
 
Net Increase in Cash and Cash Equivalents
 
 
 786 
 
 
 97 
Cash and Cash Equivalents at Beginning of Period
 
 
 509 
 
 
 1,096 
Cash and Cash Equivalents at End of Period
 
$
 1,295 
 
$
 1,193 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 38,250 
 
$
 43,615 
Net Cash Paid for Income Taxes
 
 
 26,797 
 
 
 54,032 
Noncash Acquisitions Under Capital Leases
 
 
 580 
 
 
 9,196 
Government Grants Included in Accounts Receivable at June 30,
 
 
 2,000 
 
 
 - 
Construction Expenditures Included in Current Liabilities at June 30,
 
 
 8,811 
 
 
 14,594 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.


 
108

 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to CSPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to CSPCo.  The footnotes begin on page 162.

 
Footnote
Reference
   
Significant Accounting Matters
Note 1
   
New Accounting Pronouncements
Note 2
   
Rate Matters
Note 3
   
Commitments, Guarantees and Contingencies
Note 4
   
Benefit Plans
Note 6
   
Business Segments
Note 7
   
Derivatives and Hedging
Note 8
   
Fair Value Measurements
Note 9
   
Income Taxes
Note 10
   
Financing Activities
Note 11
   
Cost Reduction Initiatives
Note 12


 
109

 










INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES


 
110

 

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

EXECUTIVE OVERVIEW

Regulatory Activity

Michigan Base Rate Case

In July 2011, I&M filed a request with the MPSC for an annual increase in Michigan base rates of $25 million and a return on equity of 11.15%.  The request includes an increase in depreciation rates that would result in a $6 million increase in depreciation expense.  I&M plans to request an interim rate increase, subject to refund, for the portion of the $25 million that excludes the depreciation rate changes and other regulatory amortizations effective in January 2012.

Cook Plant

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 $408 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.  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 reduce future net income and cash flows and impact financial condition.  See “Michigan 2009 and 2010 Power Supply Cost Recovery Reconciliations” section of Note 3 and “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

As a result of the nuclear plant situation in Japan following an earthquake, management expects the Nuclear Regulatory Commission and possibly Congress to review safety procedures and requirements for nuclear generating facilities.  This review could increase procedures and testing requirements, require physical modifications to the plant and increase future operating costs at the Cook Plant.  Management is unable to predict the impact of potential future regulation of nuclear facilities.

Litigation and Environmental Issues

In the ordinary course of business, I&M is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 162.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 227 for additional discussion of relevant factors.
 
111

 

RESULTS OF OPERATIONS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
KWH Sales/Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summary of KWH Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 1,170 
 
 
 1,210 
 
 
 3,006 
 
 
 2,975 
 
Commercial
 
 1,188 
 
 
 1,279 
 
 
 2,452 
 
 
 2,487 
 
Industrial
 
 1,871 
 
 
 1,895 
 
 
 3,715 
 
 
 3,695 
 
Miscellaneous
 
 15 
 
 
 18 
 
 
 38 
 
 
 36 
Total Retail
 
 4,244 
 
 
 4,402 
 
 
 9,211 
 
 
 9,193 
 
 
 
 
 
 
 
 
 
 
 
 
Wholesale
 
 2,408 
 
 
 1,793 
 
 
 4,504 
 
 
 3,700 
 
 
 
 
 
 
 
 
 
 
 
 
Total KWHs
 
 6,652 
 
 
 6,195 
 
 
 13,715 
 
 
 12,893 

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.

Summary of Heating and Cooling Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
June 30,
 
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in degree days)
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 228 
 
 
 95 
 
 
 2,620 
 
 
 2,278 
Normal - Heating (b)
 
 238 
 
 
 243 
 
 
 2,414 
 
 
 2,422 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 304 
 
 
 379 
 
 
 304 
 
 
 379 
Normal - Cooling (b)
 
 252 
 
 
 245 
 
 
 253 
 
 
 246 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Eastern 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.

 
112

 
Second Quarter of 2011 Compared to Second Quarter of 2010
 
 
 
 
 
Reconciliation of Second Quarter of 2010 to Second Quarter of 2011
 
Net Income
 
(in millions)
 
 
 
 
 
Second Quarter of 2010
  $ 15  
 
       
Changes in Gross Margin:
       
Retail Margins
    (9 )
FERC Municipals and Cooperatives
    (2 )
Off-system Sales
    4  
Other Revenues
    (2 )
Total Change in Gross Margin
    (9 )
 
       
Changes in Expenses and Other:
       
Other Operation and Maintenance
    32  
Depreciation and Amortization
    1  
Taxes Other Than Income Taxes
    (2 )
Other Income
    (2 )
Interest Expense
    2  
Total Change in Expenses and Other
    31  
 
       
Income Tax Expense
    (6 )
 
       
Second Quarter of 2011
  $ 31  

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

·
Retail Margins decreased $9 million primarily due to the following:
 
·
A $6 million decrease due to customer credits for a settlement relating to the Cook Plant Unit 1 (Unit 1) fire outage.  This decrease was offset by a decrease in Other Operation and Maintenance expenses.
 
·
A $5 million decrease in margins from commercial sales primarily due to lower usage.
 
·
A $3 million decrease in capacity settlements under the Interconnection Agreement.
 
These decreases were partially offset by:
 
·
A $7 million increase due to a Michigan rate settlement effective in December 2010.
·
Margins from Off-system Sales increased $4 million primarily due to higher physical sales volume.

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

·
Other Operation and Maintenance expenses decreased $32 million primarily due to the following:
 
·
A $40 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
 
·
A $6 million decrease in steam power expenses relating to the Unit 1 fire outage.  This decrease was offset by a decrease in Retail Margins.
 
These decreases were partially offset by:
 
·
A $9 million increase in transmission expense primarily due to the Transmission Agreement modification effective November 2010.
 
·
A $3 million increase in steam generation maintenance costs.
·
Income Tax Expense increased $6 million primarily due to an increase in pre-tax book income and the regulatory accounting treatment of state income taxes, partially offset by other book/tax differences which are accounted for on a flow-through basis.

 
113

 
Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010
 
 
 
 
 
 
Reconciliation of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2011
Net Income
(in millions)
 
 
 
 
 
Six Months Ended June 30, 2010
 
$
 60 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
Retail Margins
 
 
 2 
 
Off-system Sales
 
 
 6 
 
Other Revenues
 
 
 (3)
 
Total Change in Gross Margin
 
 
 5 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
Other Operation and Maintenance
 
 
 27 
 
Depreciation and Amortization
 
 
 1 
 
Taxes Other Than Income Taxes
 
 
 (3)
 
Other Income
 
 
 (3)
 
Interest Expense
 
 
 3 
 
Total Change in Expenses and Other
 
 
 25 
 
 
 
 
 
 
Income Tax Expense
 
 
 (13)
 
 
 
 
 
 
Six Months Ended June 30, 2011
 
$
 77 
 

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 $2 million primarily due to the following:
 
·
A $23 million increase due to the Michigan rate settlement effective in December 2010 and recovery of costs through trackers.
 
This increase was offset by:
 
·
A $17 million decrease in capacity settlements under the Interconnection Agreement.
 
·
A $6 million decrease due to customer credits for a settlement relating to the Unit 1 fire outage.  This decrease was offset by a decrease in Other Operation and Maintenance expenses.
·
Margins from Off-system Sales increased $6 million primarily due to higher physical sales volume.

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

·
Other Operation and Maintenance expenses decreased $27 million primarily due to the following:
 
·
A $40 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
 
·
A $6 million decrease in steam power expenses relating to the Unit 1 fire outage.  This decrease was offset by a decrease in Retail Margins.
   
These decreases were partially offset by:
 
·
A $19 million increase in transmission expense primarily due to the Transmission Agreement modification effective November 2010.
·
Income Tax Expense increased $13 million primarily due to an increase in pre-tax book income, the regulatory accounting treatment of state income taxes and federal income tax adjustments related to prior year tax returns.
 
 
114

 
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of market risk.

 
115

 


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
Three Months Ended
 
Six Months Ended
 
 
2011 
 
2010 
 
2011 
 
2010 
REVENUES
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission and Distribution
 
$
 419,627 
 
$
 408,702 
 
$
 876,489 
 
$
 846,726 
Sales to AEP Affiliates
 
 
 70,902 
 
 
 67,473 
 
 
 145,770 
 
 
 151,690 
Other Revenues - Affiliated
 
 
 28,133 
 
 
 30,685 
 
 
 52,464 
 
 
 58,651 
Other Revenues - Nonaffiliated
 
 
 2,816 
 
 
 3,055 
 
 
 7,247 
 
 
 5,904 
TOTAL REVENUES
 
 
 521,478 
 
 
 509,915 
 
 
 1,081,970 
 
 
 1,062,971 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EXPENSES
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
 
 108,322 
 
 
 102,258 
 
 
 223,384 
 
 
 221,439 
Purchased Electricity for Resale
 
 
 31,796 
 
 
 31,444 
 
 
 61,088 
 
 
 61,211 
Purchased Electricity from AEP Affiliates
 
 
 82,967 
 
 
 68,496 
 
 
 162,551 
 
 
 150,746 
Other Operation
 
 
 132,846 
 
 
 162,978 
 
 
 266,057 
 
 
 293,659 
Maintenance
 
 
 47,536 
 
 
 49,633 
 
 
 98,536 
 
 
 98,077 
Depreciation and Amortization
 
 
 33,263 
 
 
 33,971 
 
 
 67,350 
 
 
 67,802 
Taxes Other Than Income Taxes
 
 
 20,397 
 
 
 18,995 
 
 
 42,659 
 
 
 40,027 
TOTAL EXPENSES
 
 
 457,127 
 
 
 467,775 
 
 
 921,625 
 
 
 932,961 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
 
 64,351 
 
 
 42,140 
 
 
 160,345 
 
 
 130,010 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
 
 
Other Income
 
 
 3,467 
 
 
 5,601 
 
 
 7,362 
 
 
 10,521 
Interest Expense
 
 
 (24,193)
 
 
 (26,410)
 
 
 (49,384)
 
 
 (52,511)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
 
 43,625 
 
 
 21,331 
 
 
 118,323 
 
 
 88,020 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 12,239 
 
 
 6,729 
 
 
 41,510 
 
 
 28,360 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME
 
 
 31,386 
 
 
 14,602 
 
 
 76,813 
 
 
 59,660 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock Dividend Requirements
 
 
 85 
 
 
 85 
 
 
 170 
 
 
 170 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
 
$
 31,301 
 
$
 14,517 
 
$
 76,643 
 
$
 59,490 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The common stock of I&M is wholly-owned by AEP.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

 
116

 


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
Total
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – DECEMBER 31, 2009
 
$
 56,584 
 
$
 981,292 
 
$
 656,608 
 
$
 (21,701)
 
$
 1,672,783 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (51,500)
 
 
 
 
 
 (51,500)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (170)
 
 
 
 
 
 (170)
SUBTOTAL – COMMON
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,621,113 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $39
 
 
 
 
 
 
 
 
 
 
 
 72 
 
 
 72 
 
 
Amortization of Pension and OPEB Deferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Costs, Net of Tax of $235
 
 
 
 
 
 
 
 
 
 
 
 436 
 
 
 436 
NET INCOME
 
 
 
 
 
 
 
 
 59,660 
 
 
 
 
 
 59,660 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 60,168 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – JUNE 30, 2010
 
$
 56,584 
 
$
 981,292 
 
$
 664,598 
 
$
 (21,193)
 
$
 1,681,281 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – DECEMBER 31, 2010
 
$
 56,584 
 
$
 981,294 
 
$
 677,360 
 
$
 (20,889)
 
$
 1,694,349 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (37,500)
 
 
 
 
 
 (37,500)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (170)
 
 
 
 
 
 (170)
SUBTOTAL – COMMON
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,656,679 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $570
 
 
 
 
 
 
 
 
 
 
 
 1,059 
 
 
 1,059 
 
 
Amortization of Pension and OPEB Deferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Costs, Net of Tax of $255
 
 
 
 
 
 
 
 
 
 
 
 473 
 
 
 473 
NET INCOME
 
 
 
 
 
 
 
 
 76,813 
 
 
 
 
 
 76,813 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 78,345 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – JUNE 30, 2011
 
$
 56,584 
 
$
 981,294 
 
$
 716,503 
 
$
 (19,357)
 
$
 1,735,024 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

 
117

 


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)
 
 
 
2011 
 
2010 
CURRENT ASSETS
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 554 
 
$
 361 
Accounts Receivable:
 
 
 
 
 
 
 
Customers
 
 
 78,902 
 
 
 76,193 
 
Affiliated Companies
 
 
 81,812 
 
 
 149,169 
 
Accrued Unbilled Revenues
 
 
 10,189 
 
 
 19,449 
 
Miscellaneous
 
 
 10,930 
 
 
 10,968 
 
Allowance for Uncollectible Accounts
 
 
 (1,986)
 
 
 (1,692)
 
 
Total Accounts Receivable
 
 
 179,847 
 
 
 254,087 
Fuel
 
 
 66,889 
 
 
 87,551 
Materials and Supplies
 
 
 172,890 
 
 
 178,331 
Risk Management Assets
 
 
 22,341 
 
 
 27,526 
Accrued Tax Benefits
 
 
 55,784 
 
 
 71,113 
Deferred Cook Plant Fire Costs
 
 
 60,207 
 
 
 45,752 
Prepayments and Other Current Assets
 
 
 34,198 
 
 
 33,713 
TOTAL CURRENT ASSETS
 
 
 592,710 
 
 
 698,434 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
Generation
 
 
 3,803,820 
 
 
 3,774,262 
 
Transmission
 
 
 1,201,822 
 
 
 1,188,665 
 
Distribution
 
 
 1,435,632 
 
 
 1,411,095 
Other Property, Plant and Equipment (including nuclear fuel and coal mining)
 
 
 747,303 
 
 
 719,708 
Construction Work in Progress
 
 
 338,627 
 
 
 301,534 
Total Property, Plant and Equipment
 
 
 7,527,204 
 
 
 7,395,264 
Accumulated Depreciation, Depletion and Amortization
 
 
 3,180,526 
 
 
 3,124,998 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
 
 
 4,346,678 
 
 
 4,270,266 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
Regulatory Assets
 
 
 519,181 
 
 
 556,254 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 1,574,142 
 
 
 1,515,227 
Long-term Risk Management Assets
 
 
 25,069 
 
 
 31,485 
Deferred Charges and Other Noncurrent Assets
 
 
 73,782 
 
 
 77,229 
TOTAL OTHER NONCURRENT ASSETS
 
 
 2,192,174 
 
 
 2,180,195 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 7,131,562 
 
$
 7,148,895 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

 
118

 


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, 2011 and December 31, 2010
(dollars in thousands)
(Unaudited)
 
 
 
 
 
2011 
 
2010 
CURRENT LIABILITIES
 
 
 
 
 
 
Advances from Affiliates
 
$
 24,537 
 
$
 42,769 
Accounts Payable:
 
 
 
 
 
 
 
General
 
 
 82,179 
 
 
 121,665 
 
Affiliated Companies
 
 
 78,368 
 
 
 105,221 
Long-term Debt Due Within One Year - Nonaffiliated
 
 
 
 
 
 
 
(June 30, 2011 and December 31, 2010 amounts include $74,100 and $77,457,
 
 
 
 
 
 
 
respectively, related to DCC Fuel)
 
 
 151,100 
 
 
 154,457 
Risk Management Liabilities
 
 
 10,877 
 
 
 16,785 
Customer Deposits
 
 
 29,791 
 
 
 29,264 
Accrued Taxes
 
 
 65,150 
 
 
 62,637 
Accrued Interest
 
 
 27,425 
 
 
 27,444 
Other Current Liabilities
 
 
 129,028 
 
 
 140,710 
TOTAL CURRENT LIABILITIES
 
 
 598,455 
 
 
 700,952 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 1,813,994 
 
 
 1,849,769 
Long-term Risk Management Liabilities
 
 
 6,092 
 
 
 6,530 
Deferred Income Taxes
 
 
 808,287 
 
 
 760,105 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 868,919 
 
 
 852,197 
Asset Retirement Obligations
 
 
 987,400 
 
 
 963,029 
Deferred Credits and Other Noncurrent Liabilities
 
 
 305,319 
 
 
 313,892 
TOTAL NONCURRENT LIABILITIES
 
 
 4,790,011 
 
 
 4,745,522 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 5,388,466 
 
 
 5,446,474 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
 
 
 8,072 
 
 
 8,072 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
Commitments and Contingencies (Note 4)
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
 
 
Common Stock – No Par Value:
 
 
 
 
 
 
 
Authorized – 2,500,000 Shares
 
 
 
 
 
 
 
Outstanding  – 1,400,000 Shares
 
 
 56,584 
 
 
 56,584 
Paid-in Capital
 
 
 981,294 
 
 
 981,294 
Retained Earnings
 
 
 716,503 
 
 
 677,360 
Accumulated Other Comprehensive Income (Loss)
 
 
 (19,357)
 
 
 (20,889)
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 1,735,024 
 
 
 1,694,349 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
 7,131,562 
 
$
 7,148,895 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.


 
119

 


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
2011 
 
2010 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net Income
 
$
 76,813 
 
$
 59,660 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 67,350 
 
 
 67,802 
 
 
Deferred Income Taxes
 
 
 42,561 
 
 
 23,213 
 
 
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net
 
 
 23,086 
 
 
 (16,103)
 
 
Allowance for Equity Funds Used During Construction
 
 
 (7,440)
 
 
 (9,002)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 6,183 
 
 
 (4,314)
 
 
Amortization of Nuclear Fuel
 
 
 72,474 
 
 
 69,478 
 
 
Fuel Over/Under-Recovery, Net
 
 
 2,947 
 
 
 11,389 
 
 
Change in Other Noncurrent Assets
 
 
 4,433 
 
 
 7,224 
 
 
Change in Other Noncurrent Liabilities
 
 
 12,055 
 
 
 33,814 
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 74,240 
 
 
 (2,965)
 
 
 
Fuel, Materials and Supplies
 
 
 26,103 
 
 
 (26,832)
 
 
 
Accounts Payable
 
 
 (76,440)
 
 
 (31,079)
 
 
 
Accrued Taxes, Net
 
 
 13,775 
 
 
 4,470 
 
 
 
Received (Deferred) Cook Plant Fire Costs
 
 
 - 
 
 
 61,906 
 
 
 
Other Current Assets
 
 
 (887)
 
 
 (284)
 
 
 
Other Current Liabilities
 
 
 (321)
 
 
 20,087 
Net Cash Flows from Operating Activities
 
 
 336,932 
 
 
 268,464 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
Construction Expenditures
 
 
 (133,064)
 
 
 (160,797)
Change in Advances to Affiliates, Net
 
 
 - 
 
 
 (12,503)
Purchases of Investment Securities
 
 
 (492,162)
 
 
 (617,059)
Sales of Investment Securities
 
 
 464,688 
 
 
 592,263 
Acquisitions of Nuclear Fuel
 
 
 (93,230)
 
 
 (41,357)
Other Investing Activities
 
 
 17,125 
 
 
 (345)
Net Cash Flows Used for Investing Activities
 
 
 (236,643)
 
 
 (239,798)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
 
 76,624 
 
 
 84,564 
Change in Advances from Affiliates, Net
 
 
 (18,232)
 
 
 - 
Retirement of Long-term Debt – Nonaffiliated
 
 
 (116,526)
 
 
 (19,208)
Retirement of Long-term Debt – Affiliated
 
 
 - 
 
 
 (25,000)
Principal Payments for Capital Lease Obligations
 
 
 (4,317)
 
 
 (17,669)
Dividends Paid on Common Stock
 
 
 (37,500)
 
 
 (51,500)
Dividends Paid on Cumulative Preferred Stock
 
 
 (170)
 
 
 (170)
Other Financing Activities
 
 
 25 
 
 
 270 
Net Cash Flows Used for Financing Activities
 
 
 (100,096)
 
 
 (28,713)
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 193 
 
 
 (47)
Cash and Cash Equivalents at Beginning of Period
 
 
 361 
 
 
 779 
Cash and Cash Equivalents at End of Period
 
$
 554 
 
$
 732 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 47,401 
 
$
 50,759 
Net Cash Paid (Received) for Income Taxes
 
 
 (19,847)
 
 
 8,092 
Noncash Acquisitions Under Capital Leases
 
 
 1,218 
 
 
 8,844 
Construction Expenditures Included in Current Liabilities at June 30,
 
 
 36,109 
 
 
 19,220 
Acquisition of Nuclear Fuel Included in Current Liabilities at June 30,
 
 
 - 
 
 
 123 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

 
120

 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to I&M’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to I&M.  The footnotes begin on page 162.

 
Footnote
Reference
   
Significant Accounting Matters
Note 1
   
New Accounting Pronouncements
Note 2
   
Rate Matters
Note 3
   
Commitments, Guarantees and Contingencies
Note 4
   
Benefit Plans
Note 6
   
Business Segments
Note 7
   
Derivatives and Hedging
Note 8
   
Fair Value Measurements
Note 9
   
Income Taxes
Note 10
   
Financing Activities
Note 11
   
Cost Reduction Initiatives
Note 12


 
121

 










OHIO POWER COMPANY CONSOLIDATED


 
122

 

OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Ohio Customer Choice

In OPCo’s service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service.  As a result, in comparison to the second quarter of 2010 and the first six months of 2010, OPCo lost approximately $2 million and $3 million, respectively, of generation related gross margin.  Management anticipates recovery of a portion of lost margins through off-system sales, including PJM capacity revenues.

Regulatory Activity

2009 – 2011 ESPs

In April 2011, the Supreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact through a remand proceeding.  Pursuant to a May 2011 PUCO order, OPCo implemented rates subject to refund.  Certain intervenors proposed adjustments that included a reduction of deferred FAC and other regulatory assets for the period prior to June 2011 of up to $336 million, excluding carrying costs, which OPCo believes is without merit and violates the Supreme Court of Ohio decision.  The proposed adjustments also include refunds and rate reductions of related revenues beginning in June 2011 of up to $81 million.    See “Ohio Electric Security Plan Filings” section of Note 3.

January 2012 – May 2014 ESP

In January 2011, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The SSO presents redesigned generation rates by customer class.  Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013.  Under the new ESP, management estimates OPCo will have base generation revenue increases, excluding riders, of $48 million for 2012 and $60 million for 2013.  The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESP could impact the outcome of the January 2012-May 2014 ESP, though the nature and extent of that impact is not presently known.  See “Ohio Electric Security Plan Filings” section of Note 3.

Ohio Distribution Base Rate Case

In February 2011, OPCo filed with the PUCO for annual increases in distribution rates of $60 million.  The requested increase is based upon an 11.15% return on common equity to be effective January 2012.  In addition to the annual increase, OPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $159 million including approximately $84 million of unrecognized equity carrying costs.  These assets and unrecognized carrying costs would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013.  The actual balance of these distribution regulatory assets as of June 30, 2011 was $64 million excluding $45 million of unrecognized equity carrying costs.  If OPCo is not ultimately permitted to fully recover its deferrals, it would reduce future net income and cash flows and impact financial condition.  See “2011 Ohio Distribution Base Rate Case” section of Note 3.
 
Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo.  Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company.  In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo.  CSPCo and OPCo requested the reorganization transaction be effective in October 2011.  In July 2011, the FERC issued an order approving the proposed merger.  A decision is pending from the PUCO.  See “Proposed CSPCo and OPCo Merger” section of Note 3.
 
123

 

Litigation and Environmental Issues

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 162.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 227 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
KWH Sales/Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summary of KWH Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 1,547 
 
 
 1,471 
 
 
 3,871 
 
 
 3,755 
 
Commercial
 
 1,395 
 
 
 1,439 
 
 
 2,788 
 
 
 2,797 
 
Industrial
 
 3,458 
 
 
 3,236 
 
 
 6,734 
 
 
 6,294 
 
Miscellaneous
 
 15 
 
 
 16 
 
 
 35 
 
 
 36 
Total Retail
 
 6,415 
 
 
 6,162 
 
 
 13,428 
 
 
 12,882 
 
 
 
 
 
 
 
 
 
 
 
 
Wholesale
 
 1,733 
 
 
 982 
 
 
 3,641 
 
 
 2,324 
 
 
 
 
 
 
 
 
 
 
 
 
Total KWHs
 
 8,148 
 
 
 7,144 
 
 
 17,069 
 
 
 15,206 

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.

Summary of Heating and Cooling Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
June 30,
 
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in degree days)
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 207 
 
 
 136 
 
 
 2,449 
 
 
 2,293 
Normal - Heating (b)
 
 239 
 
 
 240 
 
 
 2,281 
 
 
 2,284 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 270 
 
 
 309 
 
 
 270 
 
 
 309 
Normal - Cooling (b)
 
 227 
 
 
 224 
 
 
 229 
 
 
 225 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Eastern 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.

 
124

 
Second Quarter of 2011 Compared to Second Quarter of 2010
 
 
 
 
 
Reconciliation of Second Quarter of 2010 to Second Quarter of 2011
 
Net Income
 
(in millions)
 
 
 
 
 
Second Quarter of 2010
  $ 38  
 
       
Changes in Gross Margin:
       
Retail Margins
    (5 )
Off-system Sales
    13  
Transmission Revenues
    4  
Other Revenues
    (3 )
Total Change in Gross Margin
    9  
 
       
Changes in Expenses and Other:
       
Other Operation and Maintenance
    45  
Depreciation and Amortization
    (2 )
Taxes Other Than Income Taxes
    1  
Carrying Costs Income
    2  
Interest Expense
    3  
Total Change in Expenses and Other
    49  
 
       
Income Tax Expense
    (20 )
 
       
Second Quarter of 2011
  $ 76  

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 decreased $5 million primarily due to the following:
 
·
A $7 million decrease in capacity settlements under the Interconnection Agreement.
 
·
A $7 million decrease in transmission rider revenues.
 
·
A $3 million decrease in commercial revenues mainly due to reduced usage.
 
·
A $2 million decrease attributable to customers switching to alternative competitive retail electric service (CRES) providers.
 
·
A $2 million decrease related to increased consumable and allowance expenses not recovered through the FAC.
 
These decreases were partially offset by:
 
·
A $7 million increase in revenues due to the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs.  This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
 
·
A $6 million increase in revenues due to the implementation of PUCO approved rider rates in September 2010 related to the Environmental Investment Carrying Cost Rider.
 
·
A $4 million increase in revenues due to a January 2011 Universal Service Fund surcharge rate increase.  This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
·
Margins from Off-system Sales increased $13 million primarily due to higher physical sales volumes.
·
Transmission Revenues increased $4 million primarily due to the Transmission Agreement modification effective November 2010, a portion of which is included in the Ohio Transmission Cost Recovery Rider.
 
 
125

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

·
Other Operation and Maintenance expenses decreased $45 million primarily due to the following:
 
·
A $49 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
 
·
A $7 million decrease in recoverable PJM expenses.
 
These decreases were partially offset by:
 
·
A $7 million increase in expenses due to the implementation of PUCO approved EE/PDR programs.  This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
 
·
A $4 million reserve recorded in second quarter 2011 as a result of a legal proceeding.
 
·
A $4 million increase in remitted Universal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
·
Depreciation and Amortization increased $2 million primarily due to higher depreciable property balances as a result of environmental and various other property additions.
·
Interest Expense decreased $3 million primarily as a result of the retirement of long-term debt in November 2010.
·
Income Tax Expense increased $20 million primarily due to an increase in pretax book income.

 
126

 
Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010
 
 
 
 
 
 
Reconciliation of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2011
Net Income
(in millions)
 
 
 
 
 
Six Months Ended June 30, 2010
 
$
 129 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
Retail Margins
 
 
 15 
 
Off-system Sales
 
 
 13 
 
Transmission Revenues
 
 
 8 
 
Total Change in Gross Margin
 
 
 36 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
Other Operation and Maintenance
 
 
 27 
 
Depreciation and Amortization
 
 
 (5)
 
Taxes Other Than Income Taxes
 
 
 (1)
 
Carrying Costs Income
 
 
 4 
 
Interest Expense
 
 
 5 
 
Total Change in Expenses and Other
 
 
 30 
 
 
 
 
 
 
Income Tax Expense
 
 
 (19)
 
 
 
 
 
 
Six Months Ended June 30, 2011
 
$
 176 
 

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 $15 million primarily due to the following:
 
·
A $21 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs.  This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
 
·
A $13 million increase in revenues due to the implementation of PUCO approved rider rates in September 2010 related to the Environmental Investment Carrying Cost Rider.
 
·
A $10 million increase in margins due to increases in residential and industrial customer usage.  The industrial increase was driven primarily by increased load for Ormet, a major industrial customer.
 
·
A $9 million increase in revenues due to a January 2011 Universal Service Fund surcharge rate increase.  This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
 
These increases were partially offset by:
 
·
A $19 million decrease in capacity settlements under the Interconnection Agreement.
 
·
An $8 million decrease in transmission rider revenues.
 
·
A $5 million decrease related to increased consumable and allowance expenses not recovered through the FAC.
 
·
A $3 million decrease attributable to customers switching to alternative competitive retail electric service (CRES) providers.
·
Margins from Off-system Sales increased $13 million primarily due to higher physical sales volumes.
·
Transmission Revenues increased $8 million primarily due to the Transmission Agreement modification effective November 2010, a portion of which is included in the Ohio Transmission Cost Recovery Rider.
 
 
127

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

·
Other Operation and Maintenance expenses decreased $27 million primarily due to the following:
 
·
A $49 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
 
·
An $11 million gain from the sale of land in January 2011.
 
·
A $9 million decrease in recoverable PJM expenses.
 
These decreases were partially offset by:
 
·
A $21 million increase in expenses due to the implementation of PUCO approved EE/PDR programs.  This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
 
·
A $9 million increase in remitted Universal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
 
·
A $7 million increase due to a favorable 2010 employee benefit adjustment.
 
·
A $4 million reserve recorded in second quarter 2011 as a result of a legal proceeding.
·
Depreciation and Amortization increased $5 million primarily due to higher depreciable property balances as a result of environmental and various other property additions.
·
Carrying Costs Income increased $4 million primarily due to a higher under-recovered fuel balance in 2011.
·
Interest Expense decreased $5 million primarily due to the retirement of long-term debt in November 2010.
·
Income Tax Expense increased $19 million primarily due to an increase in pretax book income, partially offset by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.
 
FINANCIAL CONDITION

LIQUIDITY

OPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  OPCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 227 for additional discussion of liquidity.

Credit Ratings

OPCo’s access to capital markets may depend on its credit ratings.  In addition, a credit rating downgrade of OPCo by one of the rating agencies could increase OPCo’s borrowing costs.  Failure to maintain investment grade ratings may constrain OPCo’s ability to participate in the Utility Money Pool or the amount of OPCo’s receivables securitized by AEP Credit.  Counterparty concerns about OPCo’s credit quality could subject OPCo to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.

CASH FLOW

Cash flows for the six months ended June 30, 2011 and 2010 were as follows:

 
 
2011
   
2010
 
 
 
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
  $ 440     $ 1,984  
Net Cash Flows from Operating Activities
    427,160       352,278  
Net Cash Flows from (Used for) Investing Activities
    (106,529 )     119,588  
Net Cash Flows Used for Financing Activities
    (319,919 )     (472,912 )
Net Increase (Decrease) in Cash and Cash Equivalents
    712       (1,046 )
Cash and Cash Equivalents at End of Period
  $ 1,152     $ 938  
 
 
128

 
Operating Activities

Net Cash Flows from Operating Activities were $427 million in 2011.  OPCo produced Net Income of $176 million during the period and noncash expense items of $184 million for Depreciation and Amortization, $57 million for Deferred Income Taxes and $51 million for Property Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The current period activity in working capital relates to a number of items.  Accounts Receivable, Net had a $71 million inflow primarily due to a settlement with AEP Ohio Transmission Company, a decrease in estimated accounts receivable balances and settlements of backup power sales.  Accounts Payable had a $51 million outflow primarily due to payments to affiliates for allowance settlements and timing differences of payments.  Fuel, Materials and Supplies had a $50 million inflow primarily due to a decrease in coal inventory reflecting increased customer usage for electricity.  The $49 million outflow from Accrued Taxes, Net is primarily due to temporary timing differences of payments for property taxes partially offset by an increase of federal income tax related accruals.

Net Cash Flows from Operating Activities were $352 million in 2010.  OPCo produced Net Income of $129 million during the period and noncash expense items of $179 million for Depreciation and Amortization and $73 million for Deferred Income Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital primarily relates to a number of items.  Accrued Taxes, Net had a $71 million outflow due to temporary timing differences of payments for property taxes and an increase of federal income tax related accruals.  Accounts Receivable, Net had a $44 million inflow primarily due to decreased sales to affiliates and settlement of allowance sales to affiliated companies.  Fuel, Materials and Supplies had a $26 million inflow primarily due to price decreases.  The $76 million increase in Fuel Over/Under-Recovery, Net reflects the deferral of fuel costs as a fuel clause was reactivated in 2009 under OPCo’s ESP.

Investing Activities

Net Cash Flows Used for Investing Activities were $107 million in 2011.  OPCo had Construction Expenditures of $112 million and a net increase of $36 million in loans to the Utility Money Pool.  Construction Expenditures were primarily related to environmental upgrades, as well as projects to improve generation and service reliability for transmission and distribution. These decreases were partially offset by $42 million in Proceeds from Sales of Assets.

Net Cash Flows from Investing Activities were $120 million in 2010.  OPCo had a net decrease of $266 million in loans to the Utility Money Pool.  This inflow was partially offset by Construction Expenditures of $148 million.  The Construction Expenditures primarily related to environmental upgrades, as well as projects to improve generation and service reliability for transmission and distribution.  Environmental upgrades include FGD projects at the Amos Plant.

Financing Activities

Net Cash Flows Used for Financing Activities were $320 million in 2011.  OPCo retired $165 million of Pollution Control Bonds in March 2011.  In addition, OPCo paid $200 million of dividends on common stock.  These decreases were partially offset by the issuance of $50 million of Pollution Control Bonds in March 2011.

Net Cash Flows Used for Financing Activities were $473 million during 2010.  OPCo retired $400 million of Senior Unsecured Notes in April 2010 and $79 million of Pollution Control Bonds in June 2010.  In addition, OPCo paid $151 million of dividends on common stock.  These decreases were partially offset by an $86 million issuance of Pollution Control Bonds in March 2010 and a $79 million issuance in May 2010.
 
 
129

 
Long-term debt issuances and retirements during the first six months of 2011 were:

Issuances
 
 
 
 
 
 
 
 
 
 
 
Principal
 
Interest
 
Due
 
Type of Debt
 
Amount
 
Rate
 
Date
 
 
 
(in thousands)
 
(%)
 
 
 
Pollution Control Bonds
 
$
 50,000 
(a)
Variable
 
2014 

(a)  
These pollution control bonds are subject to redemption earlier than the maturity date.  Consequently, this bond has been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on OPCo’s Condensed Consolidated Balance Sheets.

 
Retirements
 
 
 
 
 
 
 
 
 
 
Principal
 
Interest
 
Due
 
Type of Debt
 
Amount Paid
 
Rate
 
Date
 
 
 
(in thousands)
 
(%)
 
 
 
Pollution Control Bonds
 
$
 65,000 
 
Variable
 
2036 
 
Pollution Control Bonds
 
 
 50,000 
 
Variable
 
2014 
 
Pollution Control Bonds
 
 
 50,000 
 
Variable
 
2014 

CONTRACTUAL OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2010 Annual Report and has not changed significantly from year-end other than debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of market risk.
 
130

 


OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
Three Months Ended
 
Six Months Ended
 
 
2011 
 
2010 
 
2011 
 
2010 
REVENUES
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission and Distribution
 
$
 558,873 
 
$
 490,422 
 
$
 1,185,679 
 
$
 1,034,122 
Sales to AEP Affiliates
 
 
 213,076 
 
 
 222,561 
 
 
 438,125 
 
 
 529,329 
Other Revenues - Affiliated
 
 
 4,507 
 
 
 5,155 
 
 
 11,525 
 
 
 11,729 
Other Revenues - Nonaffiliated
 
 
 3,515 
 
 
 3,826 
 
 
 7,470 
 
 
 8,057 
TOTAL REVENUES
 
 
 779,971 
 
 
 721,964 
 
 
 1,642,799 
 
 
 1,583,237 
 
 
 
 
 
 
 
 
 
 
 
 
 
EXPENSES
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
 
 246,973 
 
 
 220,174 
 
 
 541,456 
 
 
 551,191 
Purchased Electricity for Resale
 
 
 44,098 
 
 
 38,746 
 
 
 88,995 
 
 
 77,636 
Purchased Electricity from AEP Affiliates
 
 
 38,168 
 
 
 21,583 
 
 
 65,862 
 
 
 43,774 
Other Operation
 
 
 94,669 
 
 
 146,417 
 
 
 194,387 
 
 
 235,573 
Maintenance
 
 
 69,607 
 
 
 63,472 
 
 
 133,919 
 
 
 119,703 
Depreciation and Amortization
 
 
 92,167 
 
 
 89,861 
 
 
 184,153 
 
 
 179,222 
Taxes Other Than Income Taxes
 
 
 51,005 
 
 
 52,088 
 
 
 106,166 
 
 
 105,172 
TOTAL EXPENSES
 
 
 636,687 
 
 
 632,341 
 
 
 1,314,938 
 
 
 1,312,271 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
 
 143,284 
 
 
 89,623 
 
 
 327,861 
 
 
 270,966 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 254 
 
 
 334 
 
 
 545 
 
 
 739 
Carrying Costs Income
 
 
 7,579 
 
 
 5,681 
 
 
 14,656 
 
 
 10,555 
Allowance for Equity Funds Used During Construction
 
 
 961 
 
 
 986 
 
 
 1,393 
 
 
 2,017 
Interest Expense
 
 
 (36,430)
 
 
 (39,077)
 
 
 (73,702)
 
 
 (79,052)
 
 
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
 
 115,648 
 
 
 57,547 
 
 
 270,753 
 
 
 205,225 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 39,982 
 
 
 19,999 
 
 
 94,675 
 
 
 75,774 
 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME
 
 
 75,666 
 
 
 37,548 
 
 
 176,078 
 
 
 129,451 
 
 
 
 
 
 
 
 
 
 
 
 
 
Less: Preferred Stock Dividend Requirements
 
 
 183 
 
 
 183 
 
 
 366 
 
 
 366 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
 
$
 75,483 
 
$
 37,365 
 
$
 175,712 
 
$
 129,085 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The common stock of OPCo is wholly-owned by AEP.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

 
131

 


OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
Total
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – DECEMBER 31, 2009
 
$
 321,201 
 
$
 1,123,149 
 
$
 1,908,803 
 
$
 (118,458)
 
$
 3,234,695 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (150,575)
 
 
 
 
 
 (150,575)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (366)
 
 
 
 
 
 (366)
SUBTOTAL – COMMON
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 3,083,754 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss),
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $676
 
 
 
 
 
 
 
 
 
 
 
 (1,255)
 
 
 (1,255)
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $1,897
 
 
 
 
 
 
 
 
 
 
 
 3,523 
 
 
 3,523 
NET INCOME
 
 
 
 
 
 
 
 
 129,451 
 
 
 
 
 
 129,451 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 131,719 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY –  JUNE 30, 2010
 
$
 321,201 
 
$
 1,123,149 
 
$
 1,887,313 
 
$
 (116,190)
 
$
 3,215,473 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – DECEMBER 31, 2010
 
$
 321,201 
 
$
 1,123,153 
 
$
 1,852,889 
 
$
 (128,819)
 
$
 3,168,424 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (200,000)
 
 
 
 
 
 (200,000)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (366)
 
 
 
 
 
 (366)
SUBTOTAL – COMMON
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 2,968,058 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $15
 
 
 
 
 
 
 
 
 
 
 
 29 
 
 
 29 
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $2,156
 
 
 
 
 
 
 
 
 
 
 
 4,003 
 
 
 4,003 
NET INCOME
 
 
 
 
 
 
 
 
 176,078 
 
 
 
 
 
 176,078 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 180,110 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY –  JUNE 30, 2011
 
$
 321,201 
 
$
 1,123,153 
 
$
 1,828,601 
 
$
 (124,787)
 
$
 3,148,168 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

 
132

 


OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)
 
 
 
2011 
 
2010 
CURRENT ASSETS
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 1,152 
 
$
 440 
Advances to Affiliates
 
 
 136,965 
 
 
 100,500 
Accounts Receivable:
 
 
 
 
 
 
 
Customers
 
 
 76,517 
 
 
 86,186 
 
Affiliated Companies
 
 
 161,076 
 
 
 198,845 
 
Accrued Unbilled Revenues
 
 
 6,626 
 
 
 27,928 
 
Miscellaneous
 
 
 350 
 
 
 2,368 
 
Allowance for Uncollectible Accounts
 
 
 (2,151)
 
 
 (2,184)
 
 
Total Accounts Receivable
 
 
 242,418 
 
 
 313,143 
Fuel
 
 
 219,150 
 
 
 257,289 
Materials and Supplies
 
 
 122,510 
 
 
 134,181 
Risk Management Assets
 
 
 22,515 
 
 
 30,773 
Accrued Tax Benefits
 
 
 22,291 
 
 
 69,021 
Prepayments and Other Current Assets
 
 
 31,081 
 
 
 33,998 
TOTAL CURRENT ASSETS
 
 
 798,082 
 
 
 939,345 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
Generation
 
 
 6,909,563 
 
 
 6,890,110 
 
Transmission
 
 
 1,254,300 
 
 
 1,234,677 
 
Distribution
 
 
 1,651,878 
 
 
 1,626,390 
Other Property, Plant and Equipment
 
 
 357,456 
 
 
 359,254 
Construction Work in Progress
 
 
 139,690 
 
 
 153,110 
Total Property, Plant and Equipment
 
 
 10,312,887 
 
 
 10,263,541 
Accumulated Depreciation and Amortization
 
 
 3,764,752 
 
 
 3,606,777 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
 
 
 6,548,135 
 
 
 6,656,764 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
Regulatory Assets
 
 
 1,004,684 
 
 
 934,011 
Long-term Risk Management Assets
 
 
 22,980 
 
 
 28,012 
Deferred Charges and Other Noncurrent Assets
 
 
 142,814 
 
 
 189,195 
TOTAL OTHER NONCURRENT ASSETS
 
 
 1,170,478 
 
 
 1,151,218 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 8,516,695 
 
$
 8,747,327 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

 
133

 


OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, 2011 and December 31, 2010
(Unaudited)
 
 
 
2011 
 
2010 
 
 
 
(in thousands)
CURRENT LIABILITIES
 
 
 
 
 
 
Accounts Payable:
 
 
 
 
 
 
 
General
 
$
 139,506 
 
$
 170,240 
 
Affiliated Companies
 
 
 111,042 
 
 
 136,215 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 50,000 
 
 
 165,000 
Risk Management Liabilities
 
 
 13,859 
 
 
 22,166 
Customer Deposits
 
 
 24,677 
 
 
 28,228 
Accrued Taxes
 
 
 172,622 
 
 
 229,253 
Accrued Interest
 
 
 46,444 
 
 
 46,184 
Other Current Liabilities
 
 
 98,589 
 
 
 98,687 
TOTAL CURRENT LIABILITIES
 
 
 656,739 
 
 
 895,973 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 2,364,781 
 
 
 2,364,522 
Long-term Debt – Affiliated
 
 
 200,000 
 
 
 200,000 
Long-term Risk Management Liabilities
 
 
 7,540 
 
 
 8,403 
Deferred Income Taxes
 
 
 1,558,892 
 
 
 1,531,639 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 131,188 
 
 
 126,403 
Employee Benefits and Pension Obligations
 
 
 237,579 
 
 
 246,517 
Deferred Credits and Other Noncurrent Liabilities
 
 
 195,194 
 
 
 188,830 
TOTAL NONCURRENT LIABILITIES
 
 
 4,695,174 
 
 
 4,666,314 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 5,351,913 
 
 
 5,562,287 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
 
 
 16,614 
 
 
 16,616 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
Commitments and Contingencies (Note 4)
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
 
 
Common Stock – No Par Value:
 
 
 
 
 
 
 
Authorized – 40,000,000 Shares
 
 
 
 
 
 
 
Outstanding  – 27,952,473 Shares
 
 
 321,201 
 
 
 321,201 
Paid-in Capital
 
 
 1,123,153 
 
 
 1,123,153 
Retained Earnings
 
 
 1,828,601 
 
 
 1,852,889 
Accumulated Other Comprehensive Income (Loss)
 
 
 (124,787)
 
 
 (128,819)
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 3,148,168 
 
 
 3,168,424 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
 
$
 8,516,695 
 
$
 8,747,327 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.


 
134

 


OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
2011 
 
2010 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net Income
 
$
 176,078 
 
$
 129,451 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 184,153 
 
 
 179,222 
 
 
Deferred Income Taxes
 
 
 57,132 
 
 
 72,638 
 
 
Carrying Costs Income
 
 
 (14,656)
 
 
 (10,555)
 
 
Allowance for Equity Funds Used During Construction
 
 
 (1,393)
 
 
 (2,017)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 5,285 
 
 
 2,359 
 
 
Property Taxes
 
 
 50,997 
 
 
 48,578 
 
 
Fuel Over/Under-Recovery, Net
 
 
 (38,041)
 
 
 (75,987)
 
 
Change in Other Noncurrent Assets
 
 
 (35,326)
 
 
 (7,571)
 
 
Change in Other Noncurrent Liabilities
 
 
 16,911 
 
 
 (2,326)
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 70,725 
 
 
 44,027 
 
 
 
Fuel, Materials and Supplies
 
 
 49,810 
 
 
 25,508 
 
 
 
Accounts Payable
 
 
 (51,175)
 
 
 (23,991)
 
 
 
Accrued Taxes, Net
 
 
 (49,177)
 
 
 (71,199)
 
 
 
Other Current Assets
 
 
 1,672 
 
 
 2,680 
 
 
 
Other Current Liabilities
 
 
 4,165 
 
 
 41,461 
Net Cash Flows from Operating Activities
 
 
 427,160 
 
 
 352,278 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
Construction Expenditures
 
 
 (111,851)
 
 
 (147,831)
Change in Advances to Affiliates, Net
 
 
 (36,465)
 
 
 265,601 
Acquisitions of Assets
 
 
 (1,187)
 
 
 (2,113)
Proceeds from Sales of Assets
 
 
 41,766 
 
 
 4,245 
Other Investing Activities
 
 
 1,208 
 
 
 (314)
Net Cash Flows from (Used for) Investing Activities
 
 
 (106,529)
 
 
 119,588 
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
 
 49,768 
 
 
 163,944 
Retirement of Long-term Debt – Nonaffiliated
 
 
 (165,000)
 
 
 (479,450)
Retirement of Cumulative Preferred Stock
 
 
 (1)
 
 
 - 
Principal Payments for Capital Lease Obligations
 
 
 (4,180)
 
 
 (3,903)
Dividends Paid on Common Stock
 
 
 (200,000)
 
 
 (150,575)
Dividends Paid on Cumulative Preferred Stock
 
 
 (366)
 
 
 (366)
Other Financing Activities
 
 
 (140)
 
 
 (2,562)
Net Cash Flows Used for Financing Activities
 
 
 (319,919)
 
 
 (472,912)
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 712 
 
 
 (1,046)
Cash and Cash Equivalents at Beginning of Period
 
 
 440 
 
 
 1,984 
Cash and Cash Equivalents at End of Period
 
$
 1,152 
 
$
 938 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 70,886 
 
$
 78,747 
Net Cash Paid for Income Taxes
 
 
 25,679 
 
 
 27,206 
Noncash Acquisitions Under Capital Leases
 
 
 422 
 
 
 23,489 
Construction Expenditures Included in Current Liabilities at June 30,
 
 
 17,908 
 
 
 10,567 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.


 
135

 

OHIO POWER COMPANY CONSOLIDATED
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to OPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to OPCo.  The footnotes begin on page 162.

 
Footnote
Reference
   
Significant Accounting Matters
Note 1
   
New Accounting Pronouncements
Note 2
   
Rate Matters
Note 3
   
Commitments, Guarantees and Contingencies
Note 4
   
Benefit Plans
Note 6
   
Business Segments
Note 7
   
Derivatives and Hedging
Note 8
   
Fair Value Measurements
Note 9
   
Income Taxes
Note 10
   
Financing Activities
Note 11
   
Cost Reduction Initiatives
Note 12


 
136

 














PUBLIC SERVICE COMPANY OF OKLAHOMA


 
137

 

PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Litigation and Environmental Issues

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 162.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 227 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
KWH Sales/Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summary of KWH Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 1,537 
 
 
 1,505 
 
 
 3,077 
 
 
 3,061 
 
Commercial
 
 1,389 
 
 
 1,374 
 
 
 2,520 
 
 
 2,443 
 
Industrial
 
 1,243 
 
 
 1,249 
 
 
 2,366 
 
 
 2,394 
 
Miscellaneous
 
 339 
 
 
 328 
 
 
 617 
 
 
 597 
Total Retail
 
 4,508 
 
 
 4,456 
 
 
 8,580 
 
 
 8,495 
 
 
 
 
 
 
 
 
 
 
 
 
Wholesale
 
 317 
 
 
 205 
 
 
 552 
 
 
 554 
 
 
 
 
 
 
 
 
 
 
 
 
Total KWHs
 
 4,825 
 
 
 4,661 
 
 
 9,132 
 
 
 9,049 

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.

Summary of Heating and Cooling Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
June 30,
 
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in degree days)
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 19 
 
 
 14 
 
 
 1,276 
 
 
 1,344 
Normal - Heating (b)
 
 42 
 
 
 41 
 
 
 1,100 
 
 
 1,088 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 912 
 
 
 769 
 
 
 945 
 
 
 777 
Normal - Cooling (b)
 
 624 
 
 
 621 
 
 
 637 
 
 
 634 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
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)
Western Region cooling degree days are calculated on a 65 degree temperature base.

 
138

 
Second Quarter of 2011 Compared to Second Quarter of 2010
 
 
 
 
 
Reconciliation of Second Quarter of 2010 to Second Quarter of 2011
 
Net Income
 
(in millions)
 
 
 
 
 
Second Quarter of 2010
  $ 15  
 
       
Changes in Gross Margin:
       
Retail Margins (a)
    (2 )
Total Change in Gross Margin
    (2 )
 
       
Changes in Expenses and Other:
       
Other Operation and Maintenance
    24  
Depreciation and Amortization
    3  
Taxes Other Than Income Taxes
    1  
Other Income
    1  
Interest Expense
    2  
Total Change in Expenses and Other
    31  
 
       
Income Tax Expense
    (12 )
 
       
Second Quarter of 2011
  $ 32  
 
(a)
Includes firm wholesale sales to municipals and cooperatives.
 

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

·
Retail Margins decreased $2 million primarily due to the following:
 
·
A $5 million decrease primarily due to revenue decreases from rate riders.  This decrease in retail margins had corresponding decreases to riders/trackers recognized in other expense items.
 
·
A $4 million decrease in residential and commercial margins primarily due to lower non-weather related usage.
 
These decreases were partially offset by:
 
·
A $5 million increase in residential weather-related usage primarily due to a 19% increase in cooling degree days.
 
·
A $3 million increase primarily due to decreased capacity and fuel costs.

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

·
Other Operation and Maintenance expenses decreased $24 million primarily due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
·
Depreciation and Amortization expenses decreased $3 million primarily due to a decrease in amortization of regulatory assets related to the Lawton settlement which was fully recovered in August 2010.
·
Income Tax Expense increased $12 million primarily due to an increase in pretax book income.
 

 
139

 


Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010
 
 
 
 
 
 
Reconciliation of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2011
Net Income
(in millions)
 
 
 
 
 
Six Months Ended June 30, 2010
 
$
 20 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
Retail Margins (a)
 
 
 (2)
 
Off-system Sales
 
 
 (1)
 
Other Revenues
 
 
 (2)
 
Total Change in Gross Margin
 
 
 (5)
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
Other Operation and Maintenance
 
 
 40 
 
Depreciation and Amortization
 
 
 6 
 
Other Income
 
 
 1 
 
Interest Expense
 
 
 3 
 
Total Change in Expenses and Other
 
 
 50 
 
 
 
 
 
 
Income Tax Expense
 
 
 (18)
 
 
 
 
 
 
Six Months Ended June 30, 2011
 
$
 47 
 
 
(a)
Includes firm wholesale sales to municipals and cooperatives.

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

·
Retail Margins decreased $2 million primarily due to the following:
 
·
A $10 million decrease primarily due to revenue decreases from rate riders.  This decrease in retail margins had corresponding decreases to riders/trackers recognized in other expense items.
 
This decrease was partially offset by:
 
·
A $6 million increase primarily due to decreased capacity and fuel costs.
 
·
A $4 million increase in weather-related usage primarily due to a 21% increase in cooling degree days, partially offset by lower industrial rates.
·
Other Revenues decreased $2 million primarily due to lower gains on the sale of emission allowances.

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

·
Other Operation and Maintenance expenses decreased $40 million primarily due to the following:
 
·
A $23 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
 
·
A $7 million decrease in maintenance of overhead lines primarily due to a decrease in vegetation management activities.
 
·
A $5 million decrease in operation expenses due to lower employee-related expenses.
 
·
A $4 million decrease in plant maintenance expenses resulting primarily from the 2011 deferral of generation maintenance expenses as a result of PSO’s base rate case.
·
Depreciation and Amortization expenses decreased $6 million primarily due to a decrease in amortization of regulatory assets related to the Lawton settlement which was fully recovered in August 2010.
·
Interest Expense decreased $3 million primarily due to 2010 Oklahoma income tax settlements and lower interest on long-term debt in 2011.
·
Income Tax Expense increased $18 million primarily due to an increase in pretax book income.
 
 
140

 
FINANCIAL CONDITION

LIQUIDITY

PSO participates in the Utility Money Pool, which provides access to AEP’s liquidity.  PSO relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 227 for additional discussion of liquidity.

Credit Ratings

PSO’s access to capital markets may depend on its credit ratings.  In addition, a credit rating downgrade of PSO by one of the rating agencies could increase PSO’s borrowing costs.  Failure to maintain investment grade ratings may constrain PSO’s ability to participate in the Utility Money Pool or the amount of PSO’s receivables securitized by AEP Credit.  Counterparty concerns about PSO’s credit quality could subject PSO to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.

CASH FLOW

Cash flows for the six months ended June 30, 2011 and 2010 were as follows:

 
 
 
2011 
 
2010 
 
 
 
(in thousands)
Cash and Cash Equivalents at Beginning of Period
 
$
 470 
 
$
 796 
Net Cash Flows from Operating Activities
 
 
 218,684 
 
 
 8,473 
Net Cash Flows Used for Investing Activities
 
 
 (64,693)
 
 
 (46,697)
Net Cash Flows from (Used for) Financing Activities
 
 
 (153,488)
 
 
 38,517 
Net Increase in Cash and Cash Equivalents
 
 
 503 
 
 
 293 
Cash and Cash Equivalents at End of Period
 
$
 973 
 
$
 1,089 

Operating Activities

Net Cash Flows from Operating Activities were $219 million in 2011.  PSO produced Net Income of $47 million during the period and had noncash expense items of $48 million for Depreciation and Amortization and $34 million for Deferred Income Taxes, partially offset by a $19 million increase in the deferral of Property Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $33 million inflow from Accounts Receivable, Net was primarily due to decreases in affiliated receivables.  The $30 million inflow from Accounts Payable was primarily due to increases related to fuel, purchased power and affiliated payables. The $16 million inflow from Accrued Taxes, Net was the result of an increase in property tax accruals.

Net Cash Flows from Operating Activities were $8 million in 2010.  PSO produced Net Income of $20 million during the period and had noncash expense items of $54 million for Depreciation and Amortization and $33 million for Deferred Income Taxes, partially offset by a $19 million increase in the deferral of Property Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a $38 million inflow from Accounts Payable primarily due to increases related to purchased power and affiliated payables.  The $100 million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel costs in relation to commission-approved fuel recovery rates.
 
141

 

Investing Activities

Net Cash Flows Used for Investing Activities during 2011 and 2010 were $65 million and $47 million, respectively.  Construction Expenditures of $65 million and $107 million in 2011 and 2010, respectively, were primarily for  projects to improve generation and service reliability for transmission and distribution in addition to customer service work.  Construction Expenditures in 2010 also included storm restoration work.  During 2010, PSO had a net decrease of $63 million in loans to the Utility Money Pool.

Financing Activities

Net Cash Flows Used for Financing Activities were $153 million during 2011.  PSO retired $275 million of Senior Unsecured Notes.  PSO had a net decrease of $91 million in borrowings from the Utility Money Pool.  In addition, PSO paid $33 million in common stock dividends.  These decreases were partially offset by the issuance of $250 million of Senior Unsecured Notes.

Net Cash Flows from Financing Activities were $39 million during 2010.  PSO had a net increase of $66 million in borrowings from the Utility Money Pool.  This increase was partially offset by $25 million paid in common stock dividends.

Long-term debt issuances and retirements during the first six months of 2011 were:

Issuances
 
 
 
 
 
 
 
 
 
 
 
Principal
 
Interest
 
Due
 
Type of Debt
 
Amount
 
Rate
 
Date
 
 
 
(in thousands)
 
(%)
 
 
 
Senior Unsecured Notes
 
$
 250,000 
 
4.40 
 
2021 
 
Notes Payable
 
 
 1,187 
 
3.00 
 
2026 

Retirements
 
 
 
 
 
 
 
 
 
 
 
Principal
 
Interest
 
Due
 
Type of Debt
 
Amount Paid
 
Rate
 
Date
 
 
 
(in thousands)
 
(%)
 
 
 
Senior Unsecured Notes
 
$
 200,000 
 
6.00 
 
2032 
 
Senior Unsecured Notes
 
 
 75,000 
 
4.70 
 
2011 

CONTRACTUAL OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2010 Annual Report and has not changed significantly from year-end other than debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of market risk.

 
142

 


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
2011 
 
2010 
 
2011 
 
2010 
REVENUES
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission and Distribution
 
$
 322,028 
 
$
 322,394 
 
$
 606,615 
 
$
 550,945 
Sales to AEP Affiliates
 
 
 5,785 
 
 
 4,481 
 
 
 8,581 
 
 
 13,151 
Other Revenues
 
 
 775 
 
 
 811 
 
 
 1,395 
 
 
 1,345 
TOTAL REVENUES
 
 
 328,588 
 
 
 327,686 
 
 
 616,591 
 
 
 565,441 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EXPENSES
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
 
 100,796 
 
 
 88,615 
 
 
 192,544 
 
 
 129,587 
Purchased Electricity for Resale
 
 
 46,018 
 
 
 53,555 
 
 
 87,197 
 
 
 98,535 
Purchased Electricity from AEP Affiliates
 
 
 9,111 
 
 
 10,471 
 
 
 25,722 
 
 
 21,463 
Other Operation
 
 
 48,736 
 
 
 70,837 
 
 
 93,140 
 
 
 120,499 
Maintenance
 
 
 25,152 
 
 
 27,038 
 
 
 45,873 
 
 
 57,977 
Depreciation and Amortization
 
 
 24,096 
 
 
 26,920 
 
 
 47,959 
 
 
 54,208 
Taxes Other Than Income Taxes
 
 
 10,494 
 
 
 10,985 
 
 
 21,090 
 
 
 21,285 
TOTAL EXPENSES
 
 
 264,403 
 
 
 288,421 
 
 
 513,525 
 
 
 503,554 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
 
 64,185 
 
 
 39,265 
 
 
 103,066 
 
 
 61,887 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 28 
 
 
 93 
 
 
 80 
 
 
 275 
Carrying Costs Income
 
 
 1,876 
 
 
 819 
 
 
 2,523 
 
 
 1,686 
Allowance for Equity Funds Used During Construction
 
 
 284 
 
 
 119 
 
 
 650 
 
 
 366 
Interest Expense
 
 
 (14,258)
 
 
 (15,765)
 
 
 (30,196)
 
 
 (33,128)
 
 
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
 
 52,115 
 
 
 24,531 
 
 
 76,123 
 
 
 31,086 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 20,555 
 
 
 9,042 
 
 
 29,174 
 
 
 11,458 
 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME
 
 
 31,560 
 
 
 15,489 
 
 
 46,949 
 
 
 19,628 
 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock Dividend Requirements
 
 
 49 
 
 
 49 
 
 
 98 
 
 
 103 
 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
 
$
 31,511 
 
$
 15,440 
 
$
 46,851 
 
$
 19,525 
 
 
 
 
 
 
 
 
 
 
 
 
 
The common stock of PSO is wholly-owned by AEP.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.


 
143

 


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
 
 
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
Total
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – DECEMBER 31, 2009
 
$
 157,230 
 
$
 364,231 
 
$
 290,880 
 
$
 (599)
 
$
 811,742 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (25,375)
 
 
 
 
 
 (25,375)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (103)
 
 
 
 
 
 (103)
Gain on Reacquired Preferred Stock
 
 
 
 
 
 76 
 
 
 
 
 
 
 
 
 76 
SUBTOTAL – COMMON
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 786,340 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $39
 
 
 
 
 
 
 
 
 
 
 
 72 
 
 
 72 
NET INCOME
 
 
 
 
 
 
 
 
 19,628 
 
 
 
 
 
 19,628 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 19,700 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – JUNE 30, 2010
 
$
 157,230 
 
$
 364,307 
 
$
 285,030 
 
$
 (527)
 
$
 806,040 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – DECEMBER 31, 2010
 
$
 157,230 
 
$
 364,307 
 
$
 312,441 
 
$
 8,494 
 
$
 842,472 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (32,500)
 
 
 
 
 
 (32,500)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (98)
 
 
 
 
 
 (98)
SUBTOTAL – COMMON
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 809,874 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Loss, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $407
 
 
 
 
 
 
 
 
 
 
 
 (756)
 
 
 (756)
NET INCOME
 
 
 
 
 
 
 
 
 46,949 
 
 
 
 
 
 46,949 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 46,193 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – JUNE 30, 2011
 
$
 157,230 
 
$
 364,307 
 
$
 326,792 
 
$
 7,738 
 
$
 856,067 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.


 
144

 


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
June 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)
 
 
 
2011 
 
2010 
CURRENT ASSETS
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 973 
 
$
 470 
Advances to Affiliates
 
 
 110 
 
 
 - 
Accounts Receivable:
 
 
 
 
 
 
 
Customers
 
 
 41,221 
 
 
 43,049 
 
Affiliated Companies
 
 
 34,822 
 
 
 65,070 
 
Miscellaneous
 
 
 4,353 
 
 
 5,497 
 
Allowance for Uncollectible Accounts
 
 
 (354)
 
 
 (971)
 
 
Total Accounts Receivable
 
 
 80,042 
 
 
 112,645 
Fuel
 
 
 21,806 
 
 
 20,176 
Materials and Supplies
 
 
 48,361 
 
 
 46,247 
Risk Management Assets
 
 
 490 
 
 
 14,225 
Accrued Tax Benefits
 
 
 31,824 
 
 
 38,589 
Regulatory Asset for Under-Recovered Fuel Costs
 
 
 37,317 
 
 
 37,262 
Prepayments and Other Current Assets
 
 
 14,564 
 
 
 9,416 
TOTAL CURRENT ASSETS
 
 
 235,487 
 
 
 279,030 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
Generation
 
 
 1,336,982 
 
 
 1,330,368 
 
Transmission
 
 
 680,619 
 
 
 663,994 
 
Distribution
 
 
 1,728,067 
 
 
 1,686,470 
Other Property, Plant and Equipment
 
 
 237,963 
 
 
 235,406 
Construction Work in Progress
 
 
 43,372 
 
 
 59,091 
Total Property, Plant and Equipment
 
 
 4,027,003 
 
 
 3,975,329 
Accumulated Depreciation and Amortization
 
 
 1,290,500 
 
 
 1,255,064 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
 
 
 2,736,503 
 
 
 2,720,265 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
Regulatory Assets
 
 
 261,716 
 
 
 263,545 
Long-term Risk Management Assets
 
 
 685 
 
 
 252 
Deferred Charges and Other Noncurrent Assets
 
 
 30,431 
 
 
 20,979 
TOTAL OTHER NONCURRENT ASSETS
 
 
 292,832 
 
 
 284,776 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 3,264,822 
 
$
 3,284,071 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

 
145

 


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, 2011 and December 31, 2010
(Unaudited)
 
 
 
 
 
 
 
 
 
2011 
 
2010 
 
 
 
(in thousands)
CURRENT LIABILITIES
 
 
 
 
 
 
Advances from Affiliates
 
$
 - 
 
$
 91,382 
Accounts Payable:
 
 
 
 
 
 
 
General
 
 
 93,693 
 
 
 69,155 
 
Affiliated Companies
 
 
 57,990 
 
 
 53,179 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 233 
 
 
 25,000 
Risk Management Liabilities
 
 
 876 
 
 
 922 
Customer Deposits
 
 
 44,161 
 
 
 41,217 
Accrued Taxes
 
 
 43,701 
 
 
 25,390 
Accrued Interest
 
 
 13,124 
 
 
 9,238 
Other Current Liabilities
 
 
 43,262 
 
 
 38,095 
TOTAL CURRENT LIABILITIES
 
 
 297,040 
 
 
 353,578 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 945,417 
 
 
 946,186 
Long-term Risk Management Liabilities
 
 
 159 
 
 
 197 
Deferred Income Taxes
 
 
 686,476 
 
 
 660,783 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 329,669 
 
 
 336,961 
Employee Benefits and Pension Obligations
 
 
 95,247 
 
 
 98,107 
Deferred Credits and Other Noncurrent Liabilities
 
 
 49,865 
 
 
 40,905 
TOTAL NONCURRENT LIABILITIES
 
 
 2,106,833 
 
 
 2,083,139 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 2,403,873 
 
 
 2,436,717 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
 
 
 4,882 
 
 
 4,882 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
Commitments and Contingencies (Note 4)
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
 
 
Common Stock – Par Value – $15 Per Share:
 
 
 
 
 
 
 
Authorized – 11,000,000 Shares
 
 
 
 
 
 
 
Issued – 10,482,000 Shares
 
 
 
 
 
 
 
Outstanding – 9,013,000 Shares
 
 
 157,230 
 
 
 157,230 
Paid-in Capital
 
 
 364,307 
 
 
 364,307 
Retained Earnings
 
 
 326,792 
 
 
 312,441 
Accumulated Other Comprehensive Income (Loss)
 
 
 7,738 
 
 
 8,494 
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 856,067 
 
 
 842,472 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
 3,264,822 
 
$
 3,284,071 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.


 
146

 


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
2011 
 
2010 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net Income
 
$
 46,949 
 
$
 19,628 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating
 
 
 
 
 
 
 
Activities:
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 47,959 
 
 
 54,208 
 
 
Deferred Income Taxes
 
 
 33,821 
 
 
 33,402 
 
 
Carrying Costs Income
 
 
 (2,523)
 
 
 (1,686)
 
 
Allowance for Equity Funds Used During Construction
 
 
 (650)
 
 
 (366)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 (292)
 
 
 (2,448)
 
 
Property Taxes
 
 
 (18,742)
 
 
 (18,532)
 
 
Fuel Over/Under-Recovery, Net
 
 
 (55)
 
 
 (99,776)
 
 
Change in Other Noncurrent Assets
 
 
 8,705 
 
 
 (13,891)
 
 
Change in Other Noncurrent Liabilities
 
 
 21,377 
 
 
 2,900 
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 32,603 
 
 
 (1,789)
 
 
 
Fuel, Materials and Supplies
 
 
 (3,744)
 
 
 (3,280)
 
 
 
Accounts Payable
 
 
 29,830 
 
 
 37,817 
 
 
 
Accrued Taxes, Net
 
 
 16,468 
 
 
 4,838 
 
 
 
Other Current Assets
 
 
 (3,070)
 
 
 2,760 
 
 
 
Other Current Liabilities
 
 
 10,048 
 
 
 (5,312)
Net Cash Flows from Operating Activities
 
 
 218,684 
 
 
 8,473 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
Construction Expenditures
 
 
 (65,343)
 
 
 (107,213)
Change in Advances to Affiliates, Net
 
 
 (110)
 
 
 62,695 
Other Investing Activities
 
 
 760 
 
 
 (2,179)
Net Cash Flows Used for Investing Activities
 
 
 (64,693)
 
 
 (46,697)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
 
 247,554 
 
 
 - 
Change in Advances from Affiliates, Net
 
 
 (91,382)
 
 
 66,229 
Retirement of Long-term Debt – Nonaffiliated
 
 
 (275,000)
 
 
 - 
Retirement of Cumulative Preferred Stock
 
 
 - 
 
 
 (301)
Principal Payments for Capital Lease Obligations
 
 
 (2,068)
 
 
 (2,040)
Dividends Paid on Common Stock
 
 
 (32,500)
 
 
 (25,375)
Dividends Paid on Cumulative Preferred Stock
 
 
 (98)
 
 
 (103)
Other Financing Activities
 
 
 6 
 
 
 107 
Net Cash Flows from (Used for) Financing Activities
 
 
 (153,488)
 
 
 38,517 
 
 
 
 
 
 
 
Net Increase in Cash and Cash Equivalents
 
 
 503 
 
 
 293 
Cash and Cash Equivalents at Beginning of Period
 
 
 470 
 
 
 796 
Cash and Cash Equivalents at End of Period
 
$
 973 
 
$
 1,089 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 12,293 
 
$
 30,152 
Net Cash Paid (Received) for Income Taxes
 
 
 383 
 
 
 (8,073)
Noncash Acquisitions Under Capital Leases
 
 
 415 
 
 
 13,434 
Construction Expenditures Included in Current Liabilities at June 30,
 
 
 8,319 
 
 
 13,534 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

 
147

 

PUBLIC SERVICE COMPANY OF OKLAHOMA
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to PSO’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to PSO.  The footnotes begin on page 162.

 
Footnote
Reference
   
Significant Accounting Matters
Note 1
   
New Accounting Pronouncements
Note 2
   
Rate Matters
Note 3
   
Commitments, Guarantees and Contingencies
Note 4
   
Benefit Plans
Note 6
   
Business Segments
Note 7
   
Derivatives and Hedging
Note 8
   
Fair Value Measurements
Note 9
   
Income Taxes
Note 10
   
Financing Activities
Note 11
   
Cost Reduction Initiatives
Note 12


 
148

 










SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

 
149

 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Regulatory Activity

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  SWEPCo’s share of construction costs is currently estimated to be $1.3 billion, excluding AFUDC, plus an additional $124 million for transmission, excluding AFUDC.  The APSC, LPSC and PUCT approved SWEPCo’s original application to build the Turk Plant.  In June 2010, the APSC issued an order which reversed and set aside the previously granted Certificate of Environmental Compatibility and Public Need.  Various proceedings are pending that challenge the Turk Plant’s construction and its approved wetlands and air permits.  In 2010, the motions for preliminary injunction were partially granted.  According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop.  Mitigation measures required by the permit are authorized and may be completed.  The preliminary injunction affects portions of the water intake and portions of two transmission lines.  In July 2011, the U.S. Eighth Circuit Court of Appeals affirmed the preliminary injunction.  Management is unable to predict the timing or the outcome related to this remand proceeding.

Management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service.  However, if SWEPCo is unable to complete the Turk Plant construction, including the related transmission facilities, and place the Turk Plant in service or if SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.  See “Turk Plant” section of Note 3.

Litigation and Environmental Issues

In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 162.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 227 for additional discussion of relevant factors.
 
150

 

RESULTS OF OPERATIONS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
KWH Sales/Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summary of KWH Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 1,645 
 
 
 1,390 
 
 
 3,249 
 
 
 2,989 
 
Commercial
 
 1,664 
 
 
 1,598 
 
 
 3,029 
 
 
 2,912 
 
Industrial
 
 1,425 
 
 
 1,383 
 
 
 2,676 
 
 
 2,529 
 
Miscellaneous
 
 22 
 
 
 21 
 
 
 41 
 
 
 40 
Total Retail
 
 4,756 
 
 
 4,392 
 
 
 8,995 
 
 
 8,470 
 
 
 
 
 
 
 
 
 
 
 
 
Wholesale
 
 1,787 
 
 
 1,738 
 
 
 3,665 
 
 
 3,551 
 
 
 
 
 
 
 
 
 
 
 
 
Total KWHs
 
 6,543 
 
 
 6,130 
 
 
 12,660 
 
 
 12,021 

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.

Summary of Heating and Cooling Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
June 30,
 
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in degree days)
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 17 
 
 
 5 
 
 
 866 
 
 
 1,043 
Normal - Heating (b)
 
 28 
 
 
 28 
 
 
 773 
 
 
 766 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 934 
 
 
 893 
 
 
 985 
 
 
 898 
Normal - Cooling (b)
 
 700 
 
 
 692 
 
 
 731 
 
 
 723 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
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)
Western Region cooling degree days are calculated on a 65 degree temperature base.

 
151

 
Second Quarter of 2011 Compared to Second Quarter of 2010
 
 
 
 
 
Reconciliation of Second Quarter of 2010 to Second Quarter of 2011
 
Net Income
 
(in millions)
 
 
 
 
 
Second Quarter of 2010
  $ 27  
 
       
Changes in Gross Margin:
       
Retail Margins (a)
    16  
Transmission Revenues
    (1 )
Total Change in Gross Margin
    15  
 
       
Changes in Expenses and Other:
       
Other Operation and Maintenance
    25  
Depreciation and Amortization
    (3 )
Taxes Other Than Income Taxes
    (1 )
Other Income
    (1 )
Interest Expense
    1  
Total Change in Expenses and Other
    21  
 
       
Income Tax Expense
    (12 )
 
       
Second Quarter of 2011
  $ 51  
 
(a)
Includes firm wholesale sales to municipals and cooperatives.
 

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 $16 million primarily due to:
 
·
An $11 million increase in retail sales primarily due to increases in residential and commercial customers.
 
·
A $7 million increase due to rate increases, including revenue increases from base rates in Texas and rate riders in Arkansas.
 
These increases were partially offset by:
 
·
A $2 million decrease in wholesale fuel recovery.

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

·
Other Operation and Maintenance expenses decreased $25 million primarily due to:
 
·
A $29 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
 
·
A $3 million decrease in operation expenses due to lower employee-related expenses.
 
These decreases were partially offset by:
 
·
A $5 million increase related to scheduled generation plant maintenance.
·
Depreciation and Amortization expenses increased $3 million primarily due to a greater depreciation base, including the addition of the Stall Unit which was placed into service in June 2010.
·
Income Tax Expense increased $12 million primarily due to an increase in pretax book income.

 
152

 
Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010
 
 
 
 
 
 
Reconciliation of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2011
Net Income
(in millions)
 
 
 
 
 
Six Months Ended June 30, 2010
 
$
 58 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
Retail Margins (a)
 
 
 38 
 
Off-system Sales
 
 
 (1)
 
Transmission Revenues
 
 
 (3)
 
Other Revenues
 
 
 1 
 
Total Change in Gross Margin
 
 
 35 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
Other Operation and Maintenance
 
 
 17 
 
Depreciation and Amortization
 
 
 (3)
 
Taxes Other Than Income Taxes
 
 
 (2)
 
Allowance for Equity Funds Used During Construction
 
 
 (6)
 
Interest Expense
 
 
 (3)
 
Total Change in Expenses and Other
 
 
 3 
 
 
 
 
 
 
Income Tax Expense
 
 
 (15)
 
 
 
 
 
 
Six Months Ended June 30, 2011
 
$
 81 
 
 
(a)
Includes firm wholesale sales to municipals and cooperatives.

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 $38 million primarily due to:
 
·
A $20 million increase due to rate increases, including revenue increases from base rates in Texas and rate riders in Arkansas.
 
·
A $16 million increase in retail sales primarily due to increases in residential and commercial customers.
·
Transmission Revenues decreased $3 million due to lower rates in the SPP region.

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

·
Other Operation and Maintenance expenses decreased $17 million primarily due to:
 
·
A $29 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
 
·
A $5 million decrease in operation expenses due to lower employee-related expenses.
 
These decreases were partially offset by:
 
·
A $10 million increase in distribution maintenance resulting from increased storm-related expenses.
 
·
An $8 million increase related to scheduled generation plant maintenance.
·
Depreciation and Amortization expenses increased $3 million primarily due to a greater depreciation base, including the addition of the Stall Unit which was placed into service in June 2010.
·
Allowance for Equity Funds Used During Construction decreased $6 million primarily due to the completed construction of the Stall Unit in June 2010.
·
Interest Expense increased $3 million primarily due to increased long-term debt outstanding.
·
Income Tax Expense increased $15 million primarily due an increase in pretax book income and other book/tax differences which are accounted for on a flow-through basis.
 
 
153

 
FINANCIAL CONDITION

LIQUIDITY

SWEPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  SWEPCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 227 for additional discussion of liquidity.

Credit Ratings

SWEPCo’s access to capital markets may depend on its credit ratings.  In addition, a credit rating downgrade of SWEPCo by one of the rating agencies could increase SWEPCo’s borrowing costs.  Failure to maintain investment grade ratings may constrain SWEPCo’s ability to participate in the Utility Money Pool or the amount of SWEPCo’s receivables securitized by AEP Credit.  Counterparty concerns about SWEPCo’s credit quality could subject SWEPCo to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.

CASH FLOW

Cash flows for the six months ended June 30, 2011 and 2010 were as follows:

 
 
 
2011 
 
2010 
 
 
 
(in thousands)
Cash and Cash Equivalents at Beginning of Period
 
$
 1,514 
 
$
 1,661 
Net Cash Flows from Operating Activities
 
 
 209,863 
 
 
 80,809 
Net Cash Flows Used for Investing Activities
 
 
 (194,249)
 
 
 (371,560)
Net Cash Flows from (Used for) Financing Activities
 
 
 (15,039)
 
 
 290,652 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 575 
 
 
 (99)
Cash and Cash Equivalents at End of Period
 
$
 2,089 
 
$
 1,562 

Operating Activities

Net Cash Flows from Operating Activities were $210 million in 2011.  SWEPCo produced Net Income of $81 million during the period and had noncash items of $66 million for Depreciation and Amortization and $24 million for Deferred Income Taxes, partially offset by $22 million in Allowance for Equity Funds Used During Construction and a $20 million increase in the deferral of Property Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $38 million inflow from Accounts Payable was primarily due to increases related to fuel and affiliated payables. The $25 million inflow from Accrued Taxes, Net was the result of an increase in property tax accruals.  The $25 million outflow from Fuel Over/Under-Recovery, Net was primarily due to lower fuel cost recovery and SIA refunds in Arkansas and Louisiana.

Net Cash Flows from Operating Activities were $81 million in 2010.  SWEPCo produced Net Income of $58 million during the period and had a noncash item of $63 million for Depreciation and Amortization, partially offset by $28 million in Allowance for Equity Funds Used During Construction and an $18 million increase in the deferral of Property Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $32 million inflow from Accrued Taxes, Net was the result of an increase in property tax accruals.  The $25 million outflow from Accounts Receivable, Net was primarily due to increased affiliated and jointly owned receivables, partially offset by lower construction-related receivables.  The $20 million inflow from Fuel, Materials and Supplies was primarily due to a decrease in coal and lignite inventories.  The $16 million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel costs in relation to commission-approved fuel recovery rates in Texas.
 
154

 
 
Investing Activities

Net Cash Flows Used for Investing Activities during 2011 and 2010 were $194 million and $372 million, respectively.  Construction Expenditures of $238 million and $176 million in 2011 and 2010, respectively, were primarily for generation projects at the Turk Plant and Stall Unit, as well as projects to improve service reliability for distribution and transmission.  The Stall Unit was placed in service in the second quarter of 2010.  During 2011, SWEPCo decreased loans to the Utility Money Pool by $52 million.  During 2010, SWEPCo increased loans to the Utility Money Pool by $193 million.

Financing Activities

Net Cash Flows Used for Financing Activities were $15 million during 2011.  SWEPCo paid $7 million in principal payments for capital lease obligations.  SWEPCo had a $6 million net decrease in revolving credit facility balances.

Net Cash Flows from Financing Activities were $291 million during 2010.  SWEPCo issued $350 million of Senior Unsecured Notes and $54 million of Pollution Control Bonds.  These increases were partially offset by a $54 million retirement of Pollution Control Bonds and a $50 million retirement of Notes Payable – Affiliated.

In July 2011, SWEPCo retired $41 million of 4.5% Pollution Control Bonds due in 2011.

CONTRACTUAL OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2010 Annual Report and has not changed significantly from year-end.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of market risk.
 
155

 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
Three Months Ended
 
Six Months Ended
 
 
2011 
 
2010 
 
2011 
 
2010 
REVENUES
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission and Distribution
 
$
 388,197 
 
$
 347,657 
 
$
 735,264 
 
$
 680,735 
Sales to AEP Affiliates
 
 
 10,671 
 
 
 13,231 
 
 
 26,250 
 
 
 22,564 
Other Revenues
 
 
 666 
 
 
 579 
 
 
 975 
 
 
 972 
TOTAL REVENUES
 
 
 399,534 
 
 
 361,467 
 
 
 762,489 
 
 
 704,271 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EXPENSES
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
 
 139,713 
 
 
 135,051 
 
 
 273,725 
 
 
 257,939 
Purchased Electricity for Resale
 
 
 39,691 
 
 
 22,841 
 
 
 78,280 
 
 
 64,727 
Purchased Electricity from AEP Affiliates
 
 
 5,116 
 
 
 4,211 
 
 
 7,227 
 
 
 13,963 
Other Operation
 
 
 50,722 
 
 
 82,265 
 
 
 104,790 
 
 
 140,518 
Maintenance
 
 
 34,790 
 
 
 28,133 
 
 
 64,181 
 
 
 45,552 
Depreciation and Amortization
 
 
 32,718 
 
 
 29,868 
 
 
 66,008 
 
 
 63,111 
Taxes Other Than Income Taxes
 
 
 16,730 
 
 
 15,580 
 
 
 33,696 
 
 
 31,475 
TOTAL EXPENSES
 
 
 319,480 
 
 
 317,949 
 
 
 627,907 
 
 
 617,285 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
 
 80,054 
 
 
 43,518 
 
 
 134,582 
 
 
 86,986 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 167 
 
 
 169 
 
 
 111 
 
 
 248 
Allowance for Equity Funds Used During Construction
 
 
 11,573 
 
 
 12,462 
 
 
 22,169 
 
 
 27,979 
Interest Expense
 
 
 (20,835)
 
 
 (21,475)
 
 
 (43,260)
 
 
 (40,019)
 
 
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE AND
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY EARNINGS
 
 
 70,959 
 
 
 34,674 
 
 
 113,602 
 
 
 75,194 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 20,571 
 
 
 8,707 
 
 
 33,967 
 
 
 18,863 
Equity Earnings of Unconsolidated Subsidiary
 
 
 683 
 
 
 738 
 
 
 1,263 
 
 
 1,457 
 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME
 
 
 51,071 
 
 
 26,705 
 
 
 80,898 
 
 
 57,788 
 
 
 
 
 
 
 
 
 
 
 
 
 
Less: Net Income Attributable to Noncontrolling Interest
 
 
 1,036 
 
 
 1,273 
 
 
 2,118 
 
 
 2,424 
 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME ATTRIBUTABLE TO SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDERS
 
 
 50,035 
 
 
 25,432 
 
 
 78,780 
 
 
 55,364 
 
 
 
 
 
 
 
 
 
 
 
 
 
Less: Preferred Stock Dividend Requirements
 
 
 57 
 
 
 57 
 
 
 114 
 
 
 114 
 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON
 
 
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDER
 
$
 49,978 
 
$
 25,375 
 
$
 78,666 
 
$
 55,250 
 
 
 
 
 
 
 
 
 
 
 
 
 
The common stock of SWEPCo is wholly-owned by AEP.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

 
156

 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
SWEPCo Common Shareholder
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
Noncontrolling
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
Interest
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – DECEMBER 31, 2009
 
$
 135,660 
 
$
 674,979 
 
$
 726,478 
 
$
 (12,991)
 
$
 31 
 
$
 1,524,157 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends – Nonaffiliated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (1,892)
 
 
 (1,892)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (114)
 
 
 
 
 
 
 
 
 (114)
SUBTOTAL – EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,522,151 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $48
 
 
 
 
 
 
 
 
 
 
 
 90 
 
 
 
 
 
 90 
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $253
 
 
 
 
 
 
 
 
 
 
 
 469 
 
 
 
 
 
 469 
NET INCOME
 
 
 
 
 
 
 
 
 55,364 
 
 
 
 
 
 2,424 
 
 
 57,788 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 58,347 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – JUNE 30, 2010
 
$
 135,660 
 
$
 674,979 
 
$
 781,728 
 
$
 (12,432)
 
$
 563 
 
$
 1,580,498 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – DECEMBER 31, 2010
 
$
 135,660 
 
$
 674,979 
 
$
 868,840 
 
$
 (12,491)
 
$
 361 
 
$
 1,667,349 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends – Nonaffiliated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (2,126)
 
 
 (2,126)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (114)
 
 
 
 
 
 
 
 
 (114)
SUBTOTAL – EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,665,109 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $137
 
 
 
 
 
 
 
 
 
 
 
 255 
 
 
 
 
 
 255 
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $681
 
 
 
 
 
 
 
 
 
 
 
 1,265 
 
 
 
 
 
 1,265 
NET INCOME
 
 
 
 
 
 
 
 
 78,780 
 
 
 
 
 
 2,118 
 
 
 80,898 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 82,418 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – JUNE 30, 2011
 
$
 135,660 
 
$
 674,979 
 
$
 947,506 
 
$
 (10,971)
 
$
 353 
 
$
 1,747,527 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.
 
 
157

 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)
 
 
 
2011 
 
2010 
CURRENT ASSETS
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 2,089 
 
$
 1,514 
Advances to Affiliates
 
 
 34,684 
 
 
 86,222 
Accounts Receivable:
 
 
 
 
 
 
 
 
Customers
 
 
 35,361 
 
 
 34,434 
 
 
Affiliated Companies
 
 
 31,179 
 
 
 43,219 
 
 
Miscellaneous
 
 
 19,953 
 
 
 17,739 
 
 
Allowance for Uncollectible Accounts
 
 
 (666)
 
 
 (588)
 
 
 
Total Accounts Receivable
 
 
 85,827 
 
 
 94,804 
Fuel
 
 
 
 
 
 
 
 
(June 30, 2011 and December 31, 2010 amounts include $30,966 and
 
 
 
 
 
 
 
 
$35,055, respectively, related to Sabine)
 
 
 96,458 
 
 
 91,777 
Materials and Supplies
 
 
 54,643 
 
 
 50,395 
Risk Management Assets
 
 
 1,613 
 
 
 1,209 
Deferred Income Tax Benefits
 
 
 11,719 
 
 
 15,529 
Accrued Tax Benefits
 
 
 39,235 
 
 
 37,900 
Regulatory Asset for Under-Recovered Fuel Costs
 
 
 9,470 
 
 
 758 
Prepayments and Other Current Assets
 
 
 24,451 
 
 
 24,270 
TOTAL CURRENT ASSETS
 
 
 360,189 
 
 
 404,378 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
 
Generation
 
 
 2,302,981 
 
 
 2,297,463 
 
 
Transmission
 
 
 957,937 
 
 
 943,724 
 
 
Distribution
 
 
 1,635,200 
 
 
 1,611,129 
Other Property, Plant and Equipment
 
 
 
 
 
 
 
 
(June 30, 2011 and December 31, 2010 amounts include $229,068 and
 
 
 
 
 
 
 
 
$224,857, respectively, related to Sabine)
 
 
 636,532 
 
 
 632,158 
Construction Work in Progress
 
 
 1,268,429 
 
 
 1,071,603 
Total Property, Plant and Equipment
 
 
 6,801,079 
 
 
 6,556,077 
Accumulated Depreciation and Amortization
 
 
 
 
 
 
 
 
(June 30, 2011 and December 31, 2010 amounts include $96,217 and
 
 
 
 
 
 
 
 
$91,840, respectively, related to Sabine)
 
 
 2,183,940 
 
 
 2,130,351 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
 
 
 4,617,139 
 
 
 4,425,726 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
Regulatory Assets
 
 
 349,174 
 
 
 332,698 
Long-term Risk Management Assets
 
 
 296 
 
 
 438 
Deferred Charges and Other Noncurrent Assets
 
 
 102,471 
 
 
 80,327 
TOTAL OTHER NONCURRENT ASSETS
 
 
 451,941 
 
 
 413,463 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 5,429,269 
 
$
 5,243,567 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.
 
 
158

 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2011 and December 31, 2010
(Unaudited)
 
 
 
2011 
 
2010 
 
 
 
(in thousands)
CURRENT LIABILITIES
 
 
 
 
 
 
Accounts Payable:
 
 
 
 
 
 
 
 
General
 
$
 172,556 
 
$
 162,271 
 
 
Affiliated Companies
 
 
 90,178 
 
 
 64,474 
Short-term Debt – Nonaffiliated
 
 
 - 
 
 
 6,217 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 61,135 
 
 
 41,135 
Risk Management Liabilities
 
 
 1,378 
 
 
 4,067 
Customer Deposits
 
 
 54,411 
 
 
 48,245 
Accrued Taxes
 
 
 62,715 
 
 
 30,516 
Accrued Interest
 
 
 40,034 
 
 
 39,856 
Obligations Under Capital Leases
 
 
 13,921 
 
 
 13,265 
Regulatory Liability for Over-Recovered Fuel Costs
 
 
 - 
 
 
 16,432 
Other Current Liabilities
 
 
 66,334 
 
 
 67,118 
TOTAL CURRENT LIABILITIES
 
 
 562,662 
 
 
 493,596 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 1,708,511 
 
 
 1,728,385 
Long-term Risk Management Liabilities
 
 
 156 
 
 
 338 
Deferred Income Taxes
 
 
 645,390 
 
 
 624,333 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 417,571 
 
 
 393,673 
Asset Retirement Obligations
 
 
 55,217 
 
 
 56,632 
Employee Benefits and Pension Obligations
 
 
 92,697 
 
 
 96,314 
Obligations Under Capital Leases
 
 
 112,632 
 
 
 115,399 
Deferred Credits and Other Noncurrent Liabilities
 
 
 82,211 
 
 
 62,852 
TOTAL NONCURRENT LIABILITIES
 
 
 3,114,385 
 
 
 3,077,926 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 3,677,047 
 
 
 3,571,522 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
 
 
 4,695 
 
 
 4,696 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
Commitments and Contingencies (Note 4)
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY
 
 
 
 
 
 
Common Stock – Par Value – $18 Per Share:
 
 
 
 
 
 
 
 
Authorized –  7,600,000 Shares
 
 
 
 
 
 
 
 
Outstanding  – 7,536,640 Shares
 
 
 135,660 
 
 
 135,660 
Paid-in Capital
 
 
 674,979 
 
 
 674,979 
Retained Earnings
 
 
 947,506 
 
 
 868,840 
Accumulated Other Comprehensive Income (Loss)
 
 
 (10,971)
 
 
 (12,491)
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 1,747,174 
 
 
 1,666,988 
 
 
 
 
 
 
 
Noncontrolling Interest
 
 
 353 
 
 
 361 
 
 
 
 
 
 
 
TOTAL EQUITY
 
 
 1,747,527 
 
 
 1,667,349 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 
$
 5,429,269 
 
$
 5,243,567 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.
 
 
159

 

 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
 
 
 
2011 
 
2010 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net Income
 
$
 80,898 
 
$
 57,788 
Adjustments to Reconcile Net Income to Net Cash Flows from
 
 
 
 
 
 
 
 Operating Activities:
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 66,008 
 
 
 63,111 
 
 
Deferred Income Taxes
 
 
 23,562 
 
 
 (5,742)
 
 
Allowance for Equity Funds Used During Construction
 
 
 (22,169)
 
 
 (27,979)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 (1,863)
 
 
 715 
 
 
Property Taxes
 
 
 (20,356)
 
 
 (18,105)
 
 
Fuel Over/Under-Recovery, Net
 
 
 (25,144)
 
 
 (15,619)
 
 
Change in Other Noncurrent Assets
 
 
 17,791 
 
 
 (11,364)
 
 
Change in Other Noncurrent Liabilities
 
 
 27,255 
 
 
 17,928 
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 9,062 
 
 
 (24,733)
 
 
 
Fuel, Materials and Supplies
 
 
 (8,929)
 
 
 20,096 
 
 
 
Accounts Payable
 
 
 37,823 
 
 
 (10,505)
 
 
 
Accrued Taxes, Net
 
 
 24,753 
 
 
 32,339 
 
 
 
Other Current Assets
 
 
 (1,485)
 
 
 (825)
 
 
 
Other Current Liabilities
 
 
 2,657 
 
 
 3,704 
Net Cash Flows from Operating Activities
 
 
 209,863 
 
 
 80,809 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
Construction Expenditures
 
 
 (237,834)
 
 
 (176,107)
Change in Advances to Affiliates, Net
 
 
 51,538 
 
 
 (193,437)
Other Investing Activities
 
 
 (7,953)
 
 
 (2,016)
Net Cash Flows Used for Investing Activities
 
 
 (194,249)
 
 
 (371,560)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
 
 - 
 
 
 399,411 
Credit Facility Borrowings
 
 
 27,413 
 
 
 50,339 
Retirement of Long-term Debt – Nonaffiliated
 
 
 - 
 
 
 (53,500)
Retirement of Long-term Debt – Affiliated
 
 
 - 
 
 
 (50,000)
Retirement of Cumulative Preferred Stock
 
 
 (1)
 
 
 - 
Credit Facility Repayments
 
 
 (33,630)
 
 
 (48,512)
Principal Payments for Capital Lease Obligations
 
 
 (6,655)
 
 
 (5,944)
Dividends Paid on Common Stock – Nonaffiliated
 
 
 (2,126)
 
 
 (1,892)
Dividends Paid on Cumulative Preferred Stock
 
 
 (114)
 
 
 (114)
Other Financing Activities
 
 
 74 
 
 
 864 
Net Cash Flows from (Used for) Financing Activities
 
 
 (15,039)
 
 
 290,652 
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 575 
 
 
 (99)
Cash and Cash Equivalents at Beginning of Period
 
 
 1,514 
 
 
 1,661 
Cash and Cash Equivalents at End of Period
 
$
 2,089 
 
$
 1,562 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 37,681 
 
$
 29,649 
Net Cash Paid for Income Taxes
 
 
 8,026 
 
 
 19,663 
Noncash Acquisitions Under Capital Leases
 
 
 4,378 
 
 
 380 
Construction Expenditures Included in Current Liabilities at June 30,
 
 
 96,959 
 
 
 85,870 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.
 
 
160

 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to SWEPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to SWEPCo.  The footnotes begin on page 162.

 
Footnote
Reference
   
Significant Accounting Matters
Note 1
   
New Accounting Pronouncements
Note 2
   
Rate Matters
Note 3
   
Commitments, Guarantees and Contingencies
Note 4
   
Acquisition
Note 5
   
Benefit Plans
Note 6
   
Business Segments
Note 7
   
Derivatives and Hedging
Note 8
   
Fair Value Measurements
Note 9
   
Income Taxes
Note 10
   
Financing Activities
Note 11
   
Cost Reduction Initiatives
Note 12


 
161

 
 
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to condensed financial statements that follow are a combined presentation for the Registrant Subsidiaries.  The following list indicates the registrants to which the footnotes apply:
     
1.
Significant Accounting Matters
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
     
2.
New Accounting Pronouncements
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
     
3.
Rate Matters
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
     
4.
Commitments, Guarantees and Contingencies
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
     
5.
Acquisition
SWEPCo
     
6.
Benefit Plans
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
     
7.
Business Segments
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
     
8.
Derivatives and Hedging
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
     
9.
Fair Value Measurements
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
     
10.
Income Taxes
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
     
11.
Financing Activities
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

12.
Cost Reduction Initiatives
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

 
162

 
 
1.  SIGNIFICANT ACCOUNTING MATTERS

General

The unaudited condensed 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 interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary.  Net income for the three and six months ended June 30, 2011 is not necessarily indicative of results that may be expected for the year ending December 31, 2011.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2010 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2010 as filed with the SEC on February 25, 2011.

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 they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE and other factors.  Management believes that significant assumptions and judgments were applied consistently.  In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.

SWEPCo is the primary beneficiary of Sabine.  I&M is the primary beneficiary of DCC Fuel.  APCo, CSPCo, I&M, OPCo, PSO and SWEPCo each hold a significant variable interest in AEPSC.  I&M and CSPCo each hold a significant variable interest in AEGCo.  SWEPCo holds a significant variable interest in 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 June 30, 2011 and 2010 were $30 million and $30 million, respectively, and for the six months ended June 30, 2011 and 2010 were $64 million and $73 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s Condensed Consolidated Balance Sheets.
 
163

 

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

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
June 30, 2011 and December 31, 2010
(in millions)
 
 
Sabine
ASSETS
 
2011 
 
2010 
Current Assets
 
$
 42 
 
$
 50 
Net Property, Plant and Equipment
 
 
 140 
 
 
 139 
Other Noncurrent Assets
 
 
 34 
 
 
 34 
Total Assets
 
$
 216 
 
$
 223 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
Current Liabilities
 
$
 46 
 
$
 33 
Noncurrent Liabilities
 
 
 170 
 
 
 190 
Total Liabilities and Equity
 
$
 216 
 
$
 223 

I&M has a nuclear fuel lease agreement with DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC (collectively 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.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC are separate legal entities from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on DCC Fuel LLC and DCC Fuel II LLC leases are made semi-annually and began in April 2010 and October 2010, respectively.  Payments on the DCC Fuel III LLC lease are made monthly and began in January 2011.  Payments on the DCC Fuel leases for the three months ended June 30, 2011 and 2010 were $38 million and $22 million, respectively, and for the six months ended June 30, 2011 and 2010 were $43 million and $22 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the 48, 54 and 54 month lease term, respectively.  Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  See the tables below for the classification of DCC Fuel’s assets and liabilities on I&M’s Condensed Consolidated Balance Sheets.

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

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
June 30, 2011 and December 31, 2010
(in millions)
 
 
DCC Fuel
ASSETS
 
2011 
 
2010 
Current Assets
 
$
 85 
 
$
 92 
Net Property, Plant and Equipment
 
 
 127 
 
 
 173 
Other Noncurrent Assets
 
 
 80 
 
 
 112 
Total Assets
 
$
 292 
 
$
 377 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
Current Liabilities
 
$
 76 
 
$
 79 
Noncurrent Liabilities
 
 
 216 
 
 
 298 
Total Liabilities and Equity
 
$
 292 
 
$
 377 

 
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DHLC is a mining operator which 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.  SWEPCo’s total billings from DHLC for the three months ended June 30, 2011 and 2010 were $15 million and $13 million, respectively, and for the six months ended June 30, 2011 and 2010 were $29 million and $26 million, respectively.  SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC.  SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s Condensed Consolidated Balance Sheets.

SWEPCo’s investment in DHLC was:

 
June 30, 2011
 
December 31, 2010
 
As Reported on
 
 
 
 
As Reported on
 
 
 
 
the Consolidated
Maximum
the Consolidated
 
Maximum
 
Balance Sheet
Exposure
Balance Sheet
 
Exposure
 
(in millions)
Capital Contribution from SWEPCo
$
 8 
 
$
 8 
 
$
 6 
 
$
 6 
Retained Earnings
 
 1 
 
 
 1 
 
 
 2 
 
 
 2 
SWEPCo's Guarantee of Debt
 
 - 
 
 
 54 
 
 
 - 
 
 
 48 
 
 
 
 
 
 
 
 
 
 
 
 
Total Investment in DHLC
$
 9 
 
$
 63 
 
$
 8 
 
$
 56 

AEPSC provides certain managerial and professional services to AEP’s subsidiaries.  AEP is the sole equity owner of AEPSC.  AEP management controls the activities of AEPSC.  The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost.  AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered.  AEPSC finances its operations through cost reimbursement from other AEP subsidiaries.  There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business.  AEPSC and its billings are subject to regulation by the FERC.  AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations.  AEP subsidiaries are considered to have a significant interest in AEPSC due to its activity in AEPSC’s cost reimbursement structure.  However, AEP subsidiaries do not have control over AEPSC.  AEPSC is consolidated by AEP.  In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

Total AEPSC billings to the Registrant Subsidiaries were as follows:
 
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Company
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in thousands)
APCo
 
$
 47,352 
 
$
 66,769 
 
$
 92,293 
 
$
 126,158 
CSPCo
 
 
 28,456 
 
 
 39,883 
 
 
 54,501 
 
 
 74,494 
I&M
 
 
 31,006 
 
 
 40,932 
 
 
 62,834 
 
 
 75,180 
OPCo
 
 
 44,536 
 
 
 62,675 
 
 
 82,368 
 
 
 111,779 
PSO
 
 
 21,130 
 
 
 31,443 
 
 
 40,548 
 
 
 55,179 
SWEPCo
 
 
 31,560 
 
 
 43,636 
 
 
 61,393 
 
 
 78,537 

 
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The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:
 
 
 
June 30, 2011
 
December 31, 2010
 
 
As Reported on the
 
Maximum
 
As Reported on the
 
Maximum
Company
 
Balance Sheet
 
Exposure
 
Balance Sheet
 
Exposure
 
 
(in thousands)
APCo
 
$
 17,942 
 
$
 17,942 
 
$
 23,230 
 
$
 23,230 
CSPCo
 
 
 11,581 
 
 
 11,581 
 
 
 12,676 
 
 
 12,676 
I&M
 
 
 11,674 
 
 
 11,674 
 
 
 12,980 
 
 
 12,980 
OPCo
 
 
 17,010 
 
 
 17,010 
 
 
 16,927 
 
 
 16,927 
PSO
 
 
 8,119 
 
 
 8,119 
 
 
 9,384 
 
 
 9,384 
SWEPCo
 
 
 11,932 
 
 
 11,932 
 
 
 14,465 
 
 
 14,465 
 
AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP.  AEGCo owns a 50% ownership interest in Rockport Plant Unit 1, leases a 50% interest in Rockport Plant Unit 2 and owns 100% of the Lawrenceburg Generating Station.  AEGCo sells all the output from the Rockport Plant to I&M and KPCo.   AEGCo leases the Lawrenceburg Generating Station to CSPCo.  AEP guarantees all the debt obligations of AEGCo.  I&M and CSPCo are considered to have a significant interest in AEGCo due to these transactions.  I&M and CSPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations.  In the event AEGCo would require financing or other support outside the billings to I&M, CSPCo and KPCo, this financing would be provided by AEP.  For additional information regarding AEGCo’s lease, see the “Rockport Lease” section of Note 13 in the 2010 Annual Report.

Total billings from AEGCo were as follows:
 
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Company
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in thousands)
CSPCo
 
$
 40,983 
 
$
 21,474 
 
$
 92,017 
 
$
 36,701 
I&M
 
 
 49,852 
 
 
 48,502 
 
 
 102,673 
 
 
 104,651 

The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
June 30, 2011
 
December 31, 2010
 
 
As Reported in
 
 
 
 
As Reported in
 
 
 
 
 
the Consolidated
 
Maximum
 
the Consolidated
 
Maximum
Company
 
Balance Sheet
 
Exposure
 
Balance Sheet
 
Exposure
 
 
(in thousands)
CSPCo
 
$
 13,392 
 
$
 13,392 
 
$
 18,165 
 
$
 18,165 
I&M
 
 
 26,956 
 
 
 26,956 
 
 
 27,899 
 
 
 27,899 

2.  NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business.  The following represents a summary of final pronouncements that impact the financial statements.

Pronouncements Issued During 2011

The following standard was issued during the first six months of 2011.  The following paragraphs discuss its impact on future financial statements.

ASU 2011-05 “Presentation of Comprehensive Income” (ASU 2011-05)

In June 2011, the FASB issued ASU 2011-05 eliminating the option to present the components of other comprehensive income as a part of the statement of shareholders’ equity.  The standard requires other comprehensive income be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income.  Reclassification
 
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adjustments from other comprehensive income to net income must be presented on the face of the financial statements.  This standard must be retrospectively applied to all reporting periods presented in financial reports issued after the effective date.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2011.  This standard will change the presentation of the financial statements but will not affect the calculation of net income or comprehensive income.  The Registrant Subsidiaries will adopt ASU 2011-05 effective January 1, 2012.

3.  RATE MATTERS

As discussed in the 2010 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within the 2010 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition.  The following discusses ratemaking developments in 2011 and updates the 2010 Annual Report.

Regulatory Assets Not Yet Being Recovered
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
I&M
 
 
 
 
June 30,
 
December 31,
 
June 30,
 
December 31,
 
 
 
 
2011 
 
2010 
 
2011 
 
2010 
Noncurrent Regulatory Assets (excluding fuel)
 
(in thousands)
 
(in thousands)
Regulatory assets not yet being recovered
 
 
 
 
 
 
 
 
 
 
 
 
 
pending future proceedings to determine
 
 
 
 
 
 
 
 
 
 
 
 
 
the recovery method and timing:
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
Virginia Environmental Rate Adjustment Clause
 
$
 65,348 
 
$
 55,724 
 
$
 - 
 
$
 - 
 
Deferred Wind Power Costs
 
 
 37,839 
 
 
 28,584 
 
 
 - 
 
 
 - 
 
Storm Related Costs
 
 
 25,225 
 
 
 25,225 
 
 
 - 
 
 
 - 
 
Mountaineer Carbon Capture and Storage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Product Validation Facility (a)
 
 
 19,254 
 
 
 59,866 
 
 
 - 
 
 
 - 
 
Special Rate Mechanism for Century Aluminum
 
 
 12,708 
 
 
 12,628 
 
 
 - 
 
 
 - 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 1,469 
 
 
 604 
 
 
 - 
 
 
 - 
Total Regulatory Assets Not Yet Being Recovered
 
$
 161,843 
 
$
 182,631 
 
$
 - 
 
$
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CSPCo
 
OPCo
 
 
 
 
June 30,
 
December 31,
 
June 30,
 
December 31,
 
 
 
 
2011 
 
2010 
 
2011 
 
2010 
Noncurrent Regulatory Assets (excluding fuel)
 
(in thousands)
 
(in thousands)
Regulatory assets not yet being recovered
 
 
 
 
 
 
 
 
 
 
 
 
 
pending future proceedings to determine
 
 
 
 
 
 
 
 
 
 
 
 
 
the recovery method and timing:
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
Line Extension Carrying Costs (b)
 
$
 37,240 
 
$
 33,709 
 
$
 23,709 
 
$
 21,246 
 
Customer Choice Deferrals (b)
 
 
 30,108 
 
 
 29,716 
 
 
 29,492 
 
 
 29,141 
 
Storm Related Costs (b)
 
 
 19,609 
 
 
 19,122 
 
 
 11,301 
 
 
 11,021 
 
Acquisition of Monongahela Power (b)
 
 
 8,592 
 
 
 7,929 
 
 
 - 
 
 
 - 
 
Economic Development Rider
 
 
 3,143 
 
 
 3,057 
 
 
 3,143 
 
 
 3,057 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 291 
 
 
 287 
 
 
 396 
 
 
 391 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
Acquisition of Monongahela Power (b)
 
 
 4,052 
 
 
 4,052 
 
 
 - 
 
 
 - 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 48 
 
 
 43 
 
 
 65 
 
 
 58 
Total Regulatory Assets Not Yet Being Recovered
 
$
 103,083 
 
$
 97,915 
 
$
 68,106 
 
$
 64,914 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
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PSO
 
SWEPCo
 
 
 
 
June 30,
 
December 31,
 
June 30,
 
December 31,
 
 
 
 
2011 
 
2010 
 
2011 
 
2010 
Noncurrent Regulatory Assets (excluding fuel)
 
(in thousands)
 
(in thousands)
Regulatory assets not yet being recovered
 
 
 
 
 
 
 
 
 
 
 
 
 
pending future proceedings to determine
 
 
 
 
 
 
 
 
 
 
 
 
 
the recovery method and timing:
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
Storm Related Costs (c)
 
$
 18,426 
 
$
 - 
 
$
 - 
 
$
 - 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
Storm Related Costs (c)
 
 
 - 
 
 
 17,256 
 
 
 1,239 
 
 
 1,239 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 - 
 
 
 574 
 
 
 740 
 
 
 613 
Total Regulatory Assets Not Yet Being Recovered
 
$
 18,426 
 
$
 17,830 
 
$
 1,979 
 
$
 1,852 

(a)
APCo wrote off a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC in March 2011.  See "Mountaineer Carbon Capture and Storage Project Product Validation Facility" section below.
(b)
Requested to be recovered in a distribution asset recovery rider.  See the "2011 Ohio Distribution Base Rate Case" section below.
(c)
In June 2011, an order was received approving recovery of PSO storm costs and associated carrying costs with recovery to begin in August 2011.  Starting in the second quarter of 2011, and in accordance with the order received from the OCC, PSO recorded a return on its storm related costs.

CSPCo and OPCo Rate Matters

Ohio Electric Security Plan Filings

2009 – 2011 ESPs

The PUCO issued an order in March 2009 that modified and approved CSPCo’s and OPCo’s ESPs which established rates at the start of the April 2009 billing cycle.  The ESPs are in effect through 2011.  The order also limited annual 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.  Some rate components and increases are exempt from these limitations.  CSPCo and OPCo collected the 2009 annualized revenue increase over the last nine months of 2009.

The order provided a FAC for the three-year period of the ESP.  The FAC was phased in to avoid having the resultant rate increases exceed the ordered annual caps described above.  The FAC is subject to quarterly true-ups, annual accounting audits and prudency reviews.  See the “2009 Fuel Adjustment Clause Audit” section below.  The order allowed CSPCo and OPCo to defer any unrecovered FAC costs resulting from the annual caps and to accrue associated carrying charges at their respective weighted average cost of capital.  Any deferred FAC regulatory asset balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018.  That recovery will include deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges.  See the “Ormet Interim Arrangement” section below.  The FAC deferral as of June 30, 2011 was $27 million and $526 million for CSPCo and OPCo, respectively, excluding $388 thousand and $43 million, respectively, of unrecognized equity carrying costs.

Discussed below are the significant outstanding uncertainties related to the ESP order:

The Ohio Consumers’ Counsel filed a notice of appeal with the Supreme Court of Ohio raising several issues including alleged retroactive ratemaking, recovery of carrying charges on certain environmental investments, Provider of Last Resort (POLR) charges and the decision not to offset rates by off-system sales margins.  In November 2009, the Industrial Energy Users-Ohio (IEU) filed a notice of appeal with the Supreme Court of Ohio challenging components of the ESP order including the POLR charge, the distribution riders for gridSMART® and enhanced reliability, the PUCO’s conclusion and supporting evaluation that the modified ESPs are more favorable than the expected results of a market rate offer, the unbundling of the fuel and non-fuel generation rate components, the scope and design of the fuel adjustment clause and the approval of the plan after the 150-day statutory deadline.
 
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In April 2011, the Supreme Court of Ohio (the Court) issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact through a remand proceeding.  First, the Court concluded that the PUCO's decision amounted to retroactive ratemaking.  Since the pertinent revenues were collected in 2009 and the Ohio Consumers’ Counsel did not successfully pursue the remedy of obtaining a stay of the order prior to the revenues being collected, there is no remand to the PUCO or refund to customers for this error.  Second, the Court held that the PUCO's conclusion that the POLR charge is cost-based conflicted with the evidence and remanded the issue to the PUCO for further consideration.  Third, the Court reversed the order’s legal basis for a carrying charge associated with certain environmental investments and remanded that issue to the PUCO to determine whether an alternative legal basis supports the charge.  Pursuant to a May 2011 PUCO order, CSPCo and OPCo implemented rates subject to refund and filed remand testimony in June 2011.  For the month ended June 30, 2011, CSPCo and OPCo recorded $14 million and $16 million, respectively, of revenues subject to refund.  In June 2011, the Ohio Consumers’ Counsel and the IEU filed testimony recommending a complete denial of collection of any POLR charges and carrying charges on certain environmental investments collected from 2009 through 2011.  They proposed unfavorable adjustments for CSPCo and OPCo of up to $370 million and $417 million, respectively, excluding carrying costs.  The proposed adjustments include a reduction of deferred FAC and other regulatory assets for the period prior to June 2011 of up to $298 million and $336 million for CSPCo and OPCo, respectively, which management believes is without merit and violates the Court’s decision.  The proposed adjustments also include refunds and rate reductions of related revenues beginning in June 2011 of $72 million and $81 million for CSPCo and OPCo, respectively.  Hearings were held in July 2011.

In April 2010, the IEU filed an additional notice of appeal with the Court challenging alleged retroactive ratemaking, CSPCo and OPCo's abilities to collect through the FAC amounts deferred under the Ormet interim arrangement and the approval of the plan after the 150-day statutory deadline.  In June 2011, the Court affirmed the PUCO’s decision and dismissed the IEU’s appeal.

In January 2011, the PUCO issued an order on CSPCo’s and OPCo’s 2009 SEET filings and determined that OPCo’s 2009 earnings were not significantly excessive but determined relevant CSPCo earnings exceeded the PUCO determined threshold by 2.13%.  As a result, the PUCO ordered CSPCo to refund $43 million ($28 million net of tax) of its earnings to customers, which was recorded as a revenue provision on CSPCo’s December 2010 books.  The PUCO ordered that the significantly excessive earnings be applied first to CSPCo’s FAC deferral, including unrecognized equity carrying costs, as of the date of the order, with any remaining balance to be credited to CSPCo’s customers on a per kilowatt basis.  That credit began with the first billing cycle in February 2011 and will continue through December 2011.  Several parties, including CSPCo and OPCo, filed requests for rehearing with the PUCO, which were denied in March 2011.  In May 2011, the IEU and the Ohio Energy Group filed appeals with the Court challenging the PUCO’s SEET decisions.  CSPCo and OPCo are required to file their 2010 SEET filings with the PUCO in 2011.  Based upon the approach in the PUCO 2009 order, management does not currently believe that CSPCo or OPCo had any significantly excessive earnings in 2010.

Management is unable to predict the outcome of the ESP remand proceeding and litigation discussed above.  If these proceedings, including future SEET filings, result in adverse rulings, it could reduce future net income and cash flows and impact financial condition.

January 2012 – May 2014 ESP

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing on a combined company basis for generation.  The rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The ESP also includes alternative energy resource requirements and addresses provisions regarding distribution service, energy efficiency requirements, economic development, job retention in Ohio, generation resources and other matters.  The SSO presents redesigned generation rates by customer class.  Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013.  The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESP could impact the outcome of the January 2012-May 2014 ESP, though the nature and extent of that impact is not presently known.  In July 2011, various intervenors filed testimony that generally asserts CSPCo's and OPCo's proposed SSO rates are higher than the
 
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market-rate offer, and objects to certain proposed riders as well as to the proposed non-bypassable nature of certain riders.  Additionally, the IEU and Ohio Consumers' Counsel object to revenues collected in the period 2009 through 2011 for POLR and carrying charges related to environmental investments and propose similar adjustments as discussed in the ESP remand proceeding.  See the "2009-2011 ESPs" section above.  A hearing for this case is scheduled for August 2011 and a decision is expected in the fourth quarter of 2011.

2011 Ohio Distribution Base Rate Case

In February 2011, CSPCo and OPCo filed with the PUCO for annual increases in distribution rates of $34 million and $60 million, respectively.  The requested increase is based upon an 11.15% return on common equity to be effective January 2012.

In addition to the annual increases, CSPCo and OPCo requested recovery of the projected December 31, 2012 balances of certain distribution regulatory assets of $216 million and $159 million, respectively, including approximately $102 million and $84 million, respectively, of unrecognized equity carrying costs.  These assets and unrecognized carrying costs would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013.  The actual balance of these distribution regulatory assets as of June 30, 2011 was $100 million and $64 million for CSPCo and OPCo, respectively, excluding $61 million and $45 million, respectively, of unrecognized equity carrying costs.  If CSPCo and OPCo are not ultimately permitted to fully recover their deferrals, it would reduce future net income and cash flows and impact financial condition.

Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo.  Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company.  In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo.  CSPCo and OPCo requested the reorganization transaction be effective in October 2011.  In July 2011, the FERC issued an order approving the proposed merger.  A decision is pending from the PUCO.  Management is unable to predict the outcome of this proceeding.

Requested Sporn Unit 5 Shutdown and Proposed Distribution Rider

In October 2010, OPCo filed an application with the PUCO for the approval of a December 2010 closure of Sporn Unit 5 and the simultaneous establishment of a new non-bypassable distribution rider outside the rate caps established in the 2009 – 2011 ESP proceeding.  The proposed rider would recover the net book value of the unit as well as related materials and supplies as of December 2010, which was estimated to total $59 million, as well as future closure costs incurred after December 2010.  OPCo also requested authority to record the future closure costs as a regulatory asset or regulatory liability with a weighted average cost of capital carrying charge to be included in the proposed non-bypassable distribution rider after the costs are incurred.  Pending PUCO approval, Sporn Unit 5 continues to operate.  In April 2011, intervenors filed comments opposing OPCo’s application.  A PUCO decision is pending as to whether a hearing will be ordered.  Management is unable to predict the outcome of this proceeding.
 
2009 Fuel Adjustment Clause Audit

As required under the ESP orders, the PUCO selected an outside consultant to conduct the audit of the FAC for CSPCo and OPCo for the period of January 2009 through December 2009.  In May 2010, the outside consultant provided its confidential audit report to the PUCO.  The audit report included a recommendation that the PUCO review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo’s FAC under-recovery balance.  Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009 and $14 million was recognized as a reduction to fuel expense in 2009 and 2010.  Hearings were held in August 2010.  A decision from the PUCO is pending.  Management is unable to predict the outcome of this proceeding.  If the PUCO orders any portion of the $58 million previously recognized gains or any future adjustments be used to reduce the FAC deferral, it would reduce future net income and cash flows and impact financial condition.
 
170

 

2010 Fuel Adjustment Clause Audit

In May 2011, the PUCO-selected outside consultant issued their results of the 2010 FAC audit for CSPCo and OPCo.  The audit report included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balances and determine whether the carrying costs on the balances should be net of accumulated income taxes.  As of June 30, 2011, the amount of OPCo’s carrying costs that could potentially be at risk is estimated to be $13 million, excluding $16 million of unrecognized equity carrying costs. The amount of carrying costs for CSPCo that could potentially be at risk is immaterial.  A decision from the PUCO is pending.  Management is unable to predict the outcome of this proceeding.  If the PUCO order results in a reduction in the carrying charges related to the FAC deferrals, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

CSPCo, OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet.  This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009.  In March 2009, the PUCO approved a FAC in the ESP filings and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio’s April 2011 decision referenced in the “2009-2011 ESPs” section above.  The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record regulatory assets for the difference between the approved market price and the rate paid by Ormet.  Through September 2009, the last month of the interim arrangement, CSPCo and OPCo had $30 million and $34 million, respectively, of deferred FAC related to the interim arrangement including recognized carrying charges.  These amounts exclude $1 million and $1 million, respectively, of unrecognized equity carrying costs.  In November 2009, CSPCo and OPCo requested that the PUCO approve recovery of the deferrals under the interim agreement plus a weighted average cost of capital carrying charge.  The interim arrangement deferrals are included in CSPCo’s and OPCo’s FAC phase-in deferral balances.  See “Ohio Electric Security Plan Filings” section above.  In the ESP proceeding, intervenors requested that CSPCo and OPCo be required to refund the Ormet-related regulatory assets and requested that the PUCO prevent CSPCo and OPCo from collecting the Ormet-related revenues in the future.  The PUCO did not take any action on this request in the 2009-2011 ESP proceeding.  The intervenors raised the issue again in response to CSPCo’s and OPCo’s November 2009 filing to approve recovery of the deferrals under the interim agreement and this issue remains pending before the PUCO.  If CSPCo and OPCo are not ultimately permitted to fully recover their requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Economic Development Rider

In April 2010, the IEU filed a notice of appeal of the 2009 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio.  The EDR collects from ratepayers the difference between the standard tariff and lower contract billings to qualifying industrial customers, subject to PUCO approval.  The IEU raised several issues including claims that: (a) the PUCO lost jurisdiction over CSPCo’s and OPCo’s ESP proceedings and related proceedings when the PUCO failed to issue ESP orders within the 150-day statutory deadline, (b) the EDR should not be exempt from the ESP annual rate limitations and (c) CSPCo and OPCo should not be allowed to apply a weighted average long-term debt carrying cost on deferred EDR regulatory assets.  In June 2011, the Supreme Court of Ohio affirmed the PUCO’s decision and dismissed the IEU’s appeal.

In June 2010, the IEU filed a notice of appeal of the 2010 PUCO-approved EDR with the Supreme Court of Ohio raising the same issues as noted in the 2009 EDR appeal.  In addition, the IEU added a claim that CSPCo and OPCo should not be able to take the benefits of the higher ESP rates while simultaneously challenging the ESP orders.  In June 2011, the IEU voluntarily dismissed the 2010 EDR appeal issues that were the same issues dismissed by the Supreme Court of Ohio in their 2009 EDR appeal referenced above.  A decision from the Supreme Court of Ohio is pending on the remaining issue.
 
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As of June 30, 2011, CSPCo and OPCo have incurred EDR costs of $59 million and $55 million, respectively, including carrying costs.  Of these costs, CSPCo and OPCo have collected $50 million and $39 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010.  The remaining $9 million and $16 million for CSPCo and OPCo, respectively, are recorded as deferred EDR regulatory assets.  If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund EDR revenue collected, it would reduce future net income and cash flows and impact financial condition.
 
Ohio IGCC Plant

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  Through June 30, 2011, CSPCo and OPCo have collected $12 million and $12 million, respectively, in pre-construction costs authorized in a June 2006 PUCO order and incurred $11 million and $11 million, respectively, in pre-construction costs.  As a result, CSPCo and OPCo established net regulatory liabilities of approximately $1 million and $1 million, respectively.  The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant before June 2011, any pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest.  As of June 2011, there were no active IGCC projects at other AEP sites.  In June 2011, CSPCo and OPCo filed a recommendation with the PUCO to refund to customers $2 million and $2 million, respectively, for the over-recovered pre-construction costs including interest.  Intervenors have filed motions with the PUCO requesting all collected pre-construction costs be refunded to Ohio ratepayers with interest.

Management cannot predict the outcome of any cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, such litigation would have on future net income and cash flows.  However, if CSPCo and OPCo are required to refund pre-construction costs collected in excess of the over-recovered pre-construction costs, it would reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

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% (440 MW) of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $124 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $124 million for transmission, excluding AFUDC.  As of June 30, 2011, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $1.2 billion of expenditures (including AFUDC and capitalized interest of $175 million and related transmission costs of $79 million).  As of June 30, 2011, the joint owners and SWEPCo have contractual construction commitments of approximately $211 million (including related transmission costs of $11 million).  SWEPCo’s share of the contractual construction commitments is $157 million.  If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of June 30, 2011, of approximately $101 million (including related transmission cancellation fees of $1 million).  SWEPCo’s share of the contractual construction cancellation fees would be approximately $74 million.

Discussed below are the significant outstanding uncertainties related to the Turk Plant:

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the 88 MW SWEPCo Arkansas jurisdictional share of the Turk Plant.  Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN.  The Arkansas Supreme Court ultimately concluded that the APSC erred in determining the need for additional power supply resources in a proceeding separate from the proceeding in which the APSC granted the CECPN.  However, the Arkansas Supreme Court approved the APSC’s procedure of granting CECPNs for transmission facilities in dockets separate from the Turk Plant CECPN proceeding.  SWEPCo filed a notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates.  In June 2010, the APSC issued an order which reversed and set aside the previously granted CECPN.
 
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The PUCT issued an order approving a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers.  SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful.  The Texas Industrial Energy Consumers filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because it was unnecessary to serve retail customers.  In February 2010, the Texas District Court affirmed the PUCT’s order in all respects.  In March 2010, SWEPCo and the Texas Industrial Energy Consumers appealed this decision to the Texas Court of Appeals.  Management is unable to predict the timing of the outcome related to this proceeding.

In November 2008, SWEPCo received its required air permit approval from the Arkansas Department of Environmental Quality and commenced construction at the site.  The Arkansas Pollution Control and Ecology Commission (APCEC) upheld the air permit.  The parties who unsuccessfully appealed the air permit to the APCEC filed a notice of appeal with the Circuit Court of Hempstead County, Arkansas.  In December 2010, the Circuit Court affirmed the APCEC.  In January 2011, the same parties filed a notice of appeal with the Arkansas Court of Appeals.  A decision is likely in the second half of 2011.

A wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009.  In 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts, and sought a preliminary injunction to halt construction and for a temporary restraining order.  In July 2010, the Hempstead County Hunting Club (Hunting Club) also filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of the Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws.  The plaintiffs’ federal law claims challenge the process used and terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts.  The plaintiffs’ state law claims challenge SWEPCo's ability to construct the Turk Plant without obtaining a certificate from the APSC.  In October 2010, the Federal District Court certified issues relating to the state law claims to the Arkansas Supreme Court, including whether those claims are within the primary jurisdiction of the APSC.  In May 2011, the Arkansas Supreme Court determined that these claims must first be brought before the APSC and that the federal court does not have jurisdiction to hear the state law claims.  In 2010, the motions for preliminary injunction were partially granted.  According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop.  Mitigation measures required by the permit are authorized and may be completed.  The preliminary injunction affects portions of the water intake and portions of two transmission lines.  SWEPCo appealed the issuance of the preliminary injunction to the U.S. Eighth Circuit Court of Appeals, and in July 2011, the Court of Appeals affirmed the preliminary injunction.  Management is unable to predict the timing or the outcome related to this remand proceeding.

In July 2011, SWEPCo reached an agreement in principle that would resolve all pending matters between SWEPCo, the Hunting Club and several other parties.  As a result, the Hunting Club’s challenge to the U.S. Army Corps of Engineers permit in the Federal District Court for the Western District of Arkansas will be dismissed and the Hunting Club’s appeal of the air permit will be withdrawn.  Additional judicial and administrative proceedings will also be terminated.  SWEPCo was unable to resolve claims by the Sierra Club and the Audubon Society, so their challenges to the wetlands and air permits will continue.

Management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service.  However, if SWEPCo is unable to complete the Turk Plant construction, including the related transmission facilities, and place the Turk Plant in service or if SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.
 
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Louisiana Fuel Adjustment Clause Audit

Consultants for the LPSC issued their audit report of SWEPCo’s Louisiana retail FAC recommending that the LPSC discontinue SWEPCo’s tiered sharing mechanism related to the off-system sales margins and reduce the FAC.  In April 2011, a settlement agreement was filed with the LPSC which resulted in an immaterial impact for SWEPCo.  The settlement agreement deferred the off-system sales issue to SWEPCo’s upcoming formula rate plan (FRP) extension filing, which is expected to be filed in the second half of 2011.  In June 2011, the LPSC approved the settlement agreement.
 
Louisiana 2008 Formula Rate Filing

In April 2008, SWEPCo filed its first formula rate filing under an approved three-year FRP.  SWEPCo requested an increase in its annual Louisiana retail rates of $11 million to be effective in August 2008 in order to earn the approved formula return on common equity of 10.565%.  In August 2008, as provided by the FRP, SWEPCo implemented the FRP rates, subject to refund.  During 2009, SWEPCo recorded a provision for refund of approximately $1 million after reaching a settlement in principle with intervenors.  SWEPCo began refunding customers in August 2010.  In March 2011, the LPSC approved the settlement stipulation.

Louisiana 2009 Formula Rate Filing

In April 2009, SWEPCo filed the second FRP which would increase its annual Louisiana retail rates by an additional $4 million effective in August 2009.  SWEPCo implemented the FRP rate increase as filed in August 2009, subject to refund.  Consultants for the LPSC objected to certain components of SWEPCo’s FRP calculation.  A settlement stipulation was reached by the parties and approved by the LPSC in March 2011.  The settlement stipulation provided for a $2 million refund, which was recorded in 2010 as a provision in Other Current Liabilities on SWEPCo's Condensed Consolidated Balance Sheets.  The refund to customers, with interest, will begin in August 2011.

Louisiana 2010 Formula Rate Filing

In April 2010, SWEPCo filed the third FRP which would decrease its annual Louisiana retail rates by $3 million effective in August 2010 pursuant to the approved FRP, subject to refund.  In October 2010, consultants for the LPSC objected to certain components of SWEPCo’s FRP calculations.  Hearings are scheduled for November 2011.  SWEPCo believes the rates as filed are in compliance with the FRP methodology previously approved by the LPSC.  If the LPSC disagrees with SWEPCo, it could result in refunds which could reduce future net income and cash flows.

APCo Rate Matters

2011 Virginia Biennial Base Rate Case

In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012.  The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law. APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing.  If approved, APCo’s net base rate increase would be $75 million.  In July 2011, an Attorney General witness recommended an $80 million reduction in APCo’s requested rate year capacity charges.

Rate Adjustment Clauses

In 2007, the Virginia law governing the regulation of electric utility service was amended to, among other items, provide for rate adjustment clauses (RACs) beginning in January 2009 for the timely and current recovery of costs of: (a) transmission services billed by an RTO, (b) demand side management and energy efficiency programs, (c) renewable energy programs, (d) environmental compliance projects and (e) new generation facilities, including major unit modifications.  In March 2011, APCo filed for approval of an environmental RAC, a renewable energy program RAC and a generation RAC simultaneous with the 2011 Virginia base rate filing.  The environmental RAC
 
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is requesting recovery of environmental compliance costs incurred from January 2009 through December 2010 of $38 million annually based on a two-year amortization.  The renewable energy program RAC is requesting the incremental portion of deferred wind power costs for the Camp Grove and Fowler Ridge projects of $6 million.  The generation RAC is requesting recovery of the Dresden Plant, currently under construction, which APCo has requested to purchase from AEGCo.
 
In accordance with Virginia law, APCo is deferring incremental environmental costs incurred after December 2008 and renewable energy costs incurred after August 2009 which are not being recovered in current revenues.  As of June 30, 2011, APCo has deferred $65 million of environmental costs (excluding $15 million of unrecognized equity carrying costs) and $38 million of renewable energy costs.  APCo plans to seek recovery of non-incremental deferred wind power costs ($32 million as of June 30, 2011) in future rate proceedings.  If the Virginia SCC were to disallow a portion of APCo’s deferred costs, it would reduce future net income and cash flows.

2010 West Virginia Base Rate Case

In May 2010, APCo filed a request with the WVPSC to increase APCo’s annual base rates by $140 million based upon an 11.75% return on common equity to be effective March 2011.  In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $46 million based upon a 10% return on common equity.  The settlement agreement also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011.  See “Mountaineer Carbon Capture and Storage Project” section below.  In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and $14 million of previously expensed costs related to the 2010 cost reduction initiatives, each over a period of seven years.

Mountaineer Carbon Capture and Storage Project

Product Validation Facility (PVF)

APCo and ALSTOM Power, Inc., 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 October 2009, APCo started injecting CO2 into the underground storage facilities.  The injection of CO2 required the recording of an asset retirement obligation and an offsetting regulatory asset.  In May 2011, the PVF ended operations and decommissioning of the facility began.

In APCo’s May 2010 West Virginia base rate filing, APCo requested rate base treatment of the PVF, including recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In March 2011, a WVPSC order denied the request for rate base treatment of the PVF largely due to its experimental operation.  The base rate order provided that should APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the PVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base.  As a result, APCo recorded a pretax write-off of $41 million ($26 million net of tax) in the first quarter of 2011 recorded to Other Operation expense on the Condensed Consolidated Statements of Operations.  See “2010 West Virginia Base Rate Case” section above.  As of June 30, 2011, APCo has recorded a noncurrent regulatory asset of $19 million related to the PVF.  If APCo cannot recover its remaining PVF investment and related accretion expenses, it would reduce future net income and cash flows.

Carbon Capture and Sequestration Project with the Department of Energy (DOE) (Commercial Scale Project)

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility at the Mountaineer Plant.  AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project.  The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million.  In July 2011, management informed the DOE that it will complete a Front-End Engineering and Design (FEED) study during the third quarter of 2011, but it is postponing any further CCS project activities because of the uncertainty about the regulation of CO2.  As of June 30, 2011, the project has incurred $30 million in total costs and has received $10 million of DOE eligible funding resulting in a $20 million net balance recorded in Deferred Charges and Other Noncurrent Assets on the Condensed Consolidated Balance
 
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Sheets.  In June 2011, FEED study costs were allocated among the Registrant Subsidiaries and KPCo.  Requests for recovery are in process in Michigan, Ohio and Virginia.  If the Registrant Subsidiaries are unable to recover the allocated costs of the CCS project, it would reduce future net income and cash flows.
 
APCo’s Filings for an IGCC Plant

In 2008, the Virginia SCC issued an order denying APCo’s request for a surcharge rate mechanism to provide for the timely recovery of pre-construction costs and the ongoing financing costs of the project during the construction period, as well as the capital costs, operating costs and a return on common equity once the facility is placed into commercial operation.  The order was based upon the Virginia SCC's finding that the estimated cost of the plant was uncertain and may escalate.  The Virginia SCC also expressed concerns that the estimated costs did not include a retrofitting of CCS facilities.  During 2009, based on the order received in Virginia, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional Certificate of Environmental Compatibility and Public Need granted in 2008 must be reconsidered if and when APCo proceeds with the IGCC plant.

Through June 30, 2011, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction.

APCo will not start construction of the IGCC plant until sufficient assurance of full cost recovery exists in Virginia and West Virginia.  If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs.  If the costs are not recoverable, it would reduce future net income and cash flows and impact financial condition.

APCo’s 2009 Expanded Net Energy Charge (ENEC) Filing

In September 2009, the WVPSC issued an order approving APCo’s March 2009 ENEC request.  The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $320 million and a first-year increase of $112 million, effective October 2009.

In June 2010, the WVPSC approved a settlement agreement for $86 million, including $9 million of construction surcharges related to APCo’s second year ENEC increase.  The settlement agreement allows APCo to accrue a weighted average cost of capital carrying charge on the excess under-recovery balance due to the ENEC phase-in as adjusted for the impacts of Accumulated Deferred Income Taxes.  The new rates became effective in July 2010.

In June 2011, the WVPSC issued an order approving an $88 million annual increase including $7 million of construction surcharges and $7 million of carrying charges related to APCo’s third year ENEC increase.  The order also allows APCo to accrue a fixed annual carrying cost rate of 4%.  The new rates became effective in July 2011.  Additionally, the order approved APCo’s request to purchase the Dresden Plant, currently under construction, from AEGCo and approved deferral of post in-service Dresden Plant costs, including a return, for future recovery.  As of June 30, 2011, APCo’s ENEC under-recovery balance was $387 million, excluding $8 million of unrecognized equity carrying costs, which is included in noncurrent regulatory assets.  If the WVPSC were to disallow a portion of APCo’s deferred ENEC costs, it could reduce future net income and cash flows and impact financial condition.

WPCo Merger with APCo

In a November 2009 proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division.  The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources.  Merger approvals from the WVPSC, Virginia SCC and the FERC are required.  No merger approval filings have been made.
 
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PSO Rate Matters

PSO 2008 Fuel and Purchased Power

In July 2009, the OCC initiated a proceeding to review PSO’s fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudency review of the related costs.  In March 2010, the Oklahoma Attorney General and the Oklahoma Industrial Energy Consumers (OIEC) recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of off-system sales margins decrease from 25% to 10%.  The OIEC also recommended that the OCC conduct a comprehensive review of all affiliate fuel transactions during 2007 and 2008.  In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEPEP was filed.  The testimony included unquantified refund recommendations relating to re-pricing of those ERCOT trading contracts.  Hearings were held in June 2011.  If the OCC were to issue an unfavorable decision, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

Michigan 2009 and 2010 Power Supply Cost Recovery (PSCR) Reconciliations (Cook Plant Unit 1 Fire and Shutdown)

In March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC.  The filing included an adjustment to exclude from the PSCR the incremental fuel cost of replacement power due to the Unit 1 outage from mid-December 2008 through December 2009, the period during which I&M received and recognized accidental outage insurance proceeds.  In October 2010, a settlement agreement was filed with the MPSC which included deferring the Unit 1 outage issue to the 2010 PSCR reconciliation.  In March 2011, I&M filed its 2010 PSCR reconciliation with the MPSC.  If any fuel clause revenues or accidental outage insurance proceeds have to be paid to customers, it would reduce future net income and cash flows and impact financial condition.  See the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

2011 Michigan Base Rate Case

In July 2011, I&M filed a request with the MPSC for an annual increase in Michigan base rates of $25 million and a return on equity of 11.15%.  The request includes an increase in depreciation rates that would result in a $6 million increase in depreciation expense.

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund – Affecting APCo, CSPCo, I&M and OPCo

In 2004, AEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA, to partially mitigate the loss of T&O revenues on a temporary basis through March 2006.  Intervenors objected to the temporary SECA rates.  The FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund.  The AEP East companies recognized gross SECA revenues of $220 million from 2004 through 2006 when the SECA rates terminated.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of recognized gross SECA revenues are as follows:

Company
 
(in millions)
APCo
 
$
 70.2 
CSPCo
 
 
 38.8 
I&M
 
 
 41.3 
OPCo
 
 
 53.3 

In 2006, a FERC Administrative Law Judge (ALJ) issued an initial decision finding that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.  The ALJ also found that any unpaid SECA rates must be paid in the recommended reduced amount.
 
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AEP filed briefs jointly with other affected companies asking the FERC to reverse the decision.  In May 2010, the FERC issued an order that generally supports AEP’s position and requires a compliance filing to be filed with the FERC by August 2010.  In June 2010, AEP and other affected companies filed a joint request for rehearing with the FERC.
 
The AEP East companies provided reserves for net refunds for SECA settlements totaling $44 million applicable to the $220 million of SECA revenues collected.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the provision are as follows:

Company
 
(in millions)
APCo
 
$
 14.1 
CSPCo
 
 
 7.8 
I&M
 
 
 8.3 
OPCo
 
 
 10.7 

Settlements approved by the FERC consumed $10 million of the reserve for refunds applicable to $112 million of SECA revenue.  In December 2010, the FERC issued an order approving a settlement agreement resulting in the collection of $2 million of previously deemed uncollectible SECA revenue.  Therefore, the AEP East companies reduced their reserves for net refunds for SECA settlements by $2 million.  The balance in the reserve for future settlements as of June 30, 2011 was $32 million.  APCo’s, CSPCo’s, I&M’s and OPCo’s reserve balances as of June 30, 2011 were:

Company
 
June 30, 2011
 
 
(in millions)
APCo
 
$
 10.0 
CSPCo
 
 
 5.6 
I&M
 
 
 5.9 
OPCo
 
 
 7.6 

In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC.  If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million.  The AEP East companies could also potentially receive payments up to approximately $10 million including estimated interest of $3 million.  A decision is pending from the FERC.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of potential refund payments and potential payments to be received are as follows:

 
 
Potential
 
Potential
 
 
Refund
 
Payments to
Company
 
Payments
 
be Received
 
 
(in millions)
APCo
 
$
 6.4 
 
$
 3.2 
CSPCo
 
 
 3.5 
 
 
 1.8 
I&M
 
 
 3.7 
 
 
 1.9 
OPCo
 
 
 4.8 
 
 
 2.4 

Based on the AEP East companies’ analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the May 2010 order or the compliance filing be made final.  Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.

Possible Termination of the Interconnection Agreement – Affecting APCo, CSPCo, I&M and OPCo

In December 2010, each of the AEP Power Pool members gave notice to AEPSC and each other of their decision to terminate the Interconnection Agreement effective January 2014 or such other date approved by FERC, subject to state regulatory input.  No filings have been made at the FERC.  It is unknown at this time whether the AEP Power Pool will be replaced by a new agreement among some or all of the members, whether individual companies will
 
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enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.  This decision to terminate is subject to management’s ongoing evaluation.  The AEP Power Pool members may revoke their notices of termination.  If any of the AEP Power Pool members experience decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

PJM/MISO Market Flow Calculation Settlement Adjustments - Affecting APCo, CSPCo, I&M and OPCo

During 2009, an analysis conducted by MISO and PJM discovered several instances of unaccounted for power flows on numerous coordinated flowgates.  These flows affected the settlement data for congestion revenues and expenses and dated back to the start of the MISO market in 2005.  In January 2011, PJM and MISO reached a settlement agreement where the parties agreed to net various issues to zero.  In June 2011, the FERC approved the settlement agreement.

Modification of the Transmission Coordination Agreement (TCA) – Affecting PSO and SWEPCo

PSO, SWEPCo and TNC are parties to the TCA, originally dated January 1, 1997, as amended.  The TCA provides for the allocation among the parties of revenues collected for transmission and ancillary services provided under the Open Access Transmission Tariff (OATT).

In April 2011, the FERC accepted proposed revisions to the TCA.  Under this amendment, TNC was removed from the TCA.  In addition, the amended TCA provides for the allocation of SPP OATT revenues between PSO and SWEPCo based on the SPP formula rate revenue requirements for transmission investment and related expenses of each company.  The amended TCA is effective May 1, 2011.

4.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business.  In addition, their business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the financial statements.  The Commitments, Guarantees and Contingencies note within the 2010 Annual Report should be read in conjunction with this report.

GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.”  There is no collateral held in relation to any guarantees.  In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters of Credit – Affecting APCo, I&M, OPCo and SWEPCo

Certain Registrant Subsidiaries enter into standby letters of credit with third parties.  These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves.

AEP has two $1.5 billion credit facilities, under which up to $1.35 billion may be issued as letters of credit.  In July 2011, AEP replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015.  As of June 30, 2011, the maximum future payments of the letters of credit were as follows:

Company
 
Amount
 
Maturity
 
 
(in thousands)
 
 
I&M
 
$
 150 
 
March 2012
SWEPCo
 
 
 4,448 
 
March 2012

 
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In March 2011, the Registrant Subsidiaries and certain other companies in the AEP System terminated a $478 million credit agreement that was scheduled to mature in April 2011 and was used to support variable rate Pollution Control Bonds.  In March 2011, certain variable rate Pollution Control Bonds were remarketed and supported by bilateral letters of credit for $361 million while others were reacquired and are being held in trust.  As of June 30, 2011, $472 million of variable rate Pollution Control Bonds were remarketed or reacquired as follows:

 
 
June 30, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reacquired
 
Bilateral
 
Maturity of
 
 
 
 
 
and Held
 
Letters of
 
Bilateral Letters
Company
 
Remarketed
 
in Trust
 
Credit Issued
 
of Credit
 
 
(in thousands)
 
 
APCo
 
$
229,650 
 
$
 - 
 
$
 232,293 
 
March 2013 to March 2014
I&M
 
 
77,000 
 
 
 - 
 
 
 77,886 
 
March 2013
OPCo
 
 
50,000 
 
 
115,000 
 
 
 50,575 
 
March 2013

Guarantees of Third-Party Obligations – Affecting SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of approximately $65 million.  In July 2011, SWEPCo’s guarantee was increased to $100 million due to expansion of the mining area.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), a consolidated variable interest entity.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  As of June 30, 2011, SWEPCo has collected approximately $51 million through a rider for final mine closure and reclamation costs, of which $1 million is recorded in Other Current Liabilities, $30 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $20 million is recorded in Asset Retirement Obligations on SWEPCo’s Condensed Consolidated Balance Sheets.

Sabine charges SWEPCo, its only customer, all of its costs.  SWEPCo passes these costs to customers through its fuel clause.

Indemnifications and Other Guarantees – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of June 30, 2011, there were no material liabilities recorded for any indemnifications.

The AEP East companies, PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to power purchase and sale activity conducted pursuant to the SIA.

Master Lease Agreements

The Registrant Subsidiaries lease certain equipment under master lease agreements.  In December 2010, management signed a new master lease agreement with GE Capital Commercial Inc. (GE) to replace existing operating and capital leases with GE.  These assets were included in existing master lease agreements that were to be terminated in 2011 since GE exercised the termination provision related to these leases in 2008.  Certain previously leased assets were not included in the 2010 refinancing, but were purchased in January 2011.
 
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For equipment under the GE master lease agreements, the lessor is guaranteed receipt of up to 78% of the unamortized balance of the equipment at the end of the lease term.  If the fair value of the leased equipment is below the unamortized balance at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the fair value and the unamortized balance, with the total guarantee not to exceed 78% of the unamortized balance.  For equipment under other master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee.  At June 30, 2011, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:

 
 
Maximum
Company
 
Potential Loss
 
 
(in thousands)
APCo
 
$
 1,450 
CSPCo
 
 
 986 
I&M
 
 
 1,867 
OPCo
 
 
 1,381 
PSO
 
 
 768 
SWEPCo
 
 
 2,727 

Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignments are accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $16 million for I&M and $18 million for SWEPCo for the remaining railcars as of June 30, 2011.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 84% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  I&M’s maximum potential loss related to the guarantee is approximately $12 million and SWEPCo’s is approximately $13 million assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, management believes that the fair value would produce a sufficient sales price to avoid any loss.

ENVIRONMENTAL CONTINGENCIES

Carbon Dioxide Public Nuisance Claims – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority.  The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants.  The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming and sought injunctive relief in the form of specific emission reduction commitments from the defendants.  The trial court dismissed the lawsuits.
 
In September 2009, the Second Circuit Court of Appeals issued a ruling on appeal remanding the cases to the Federal District Court for the Southern District of New York.  The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate CO2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s
 
181

 
 
administration to secure the relief sought in their complaints.  The court stated that Congress could enact comprehensive legislation to regulate CO2 emissions or that the Federal EPA could regulate CO2 emissions under existing CAA authorities and that either of these actions could override any decision made by the district court under federal common law.  The Second Circuit did not rule on whether the plaintiffs could proceed with their state common law nuisance claims.  In 2010, the U.S. Supreme Court granted the defendants’ petition for review.  In June 2011, the U.S. Supreme Court reversed and remanded the case to the Court of Appeals, finding that plaintiffs’ federal common law claims are displaced by the regulatory authority granted to the Federal EPA under the CAA.

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing.  An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place.  Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision.  The petition was denied in January 2011.  Plaintiffs refiled their complaint in federal district court.  Management believes the claims are without merit, and in addition to other defenses, are barred by the doctrine of collateral estoppel and the applicable statute of limitations.  Management intends to vigorously defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Alaskan Villages’ Claims – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  The plaintiffs appealed the decision.  Briefing is complete and no date has been set for oral argument.  The defendants requested that the court defer setting this case for oral argument until after the Supreme Court issues its decision in the CO2 public nuisance case discussed above.  The court entered an order deferring argument until after June 2011 and the parties requested supplemental briefing on the impact of the Supreme Court’s decision.   Management believes the action is without merit and intends to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, the generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials.  The Registrant Subsidiaries currently incur costs to dispose of these substances safely.
 
In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M started remediation work in accordance with a plan approved by MDEQ.  I&M’s provision is approximately $11 million.  As the remediation work is completed, I&M’s cost may continue to increase as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ.  Management cannot predict the amount of additional cost, if any.
 
182

 

Amos Plant – State and Federal Enforcement Proceedings – Affecting APCo and OPCo

In March 2010, APCo and OPCo received a letter from the West Virginia Department of Environmental Protection, Division of Air Quality (DAQ), alleging that at various times in 2007 through 2009 the units at Amos Plant reported periods of excess opacity (indicator of compliance with PM emission limits) that lasted for more than 30 consecutive minutes in a 24-hour period and that certain required notifications were not made.  Management met with representatives of DAQ to discuss these occurrences and the steps taken to prevent a recurrence.  DAQ indicated that additional enforcement action may be taken, including imposition of a civil penalty of approximately $240 thousand.  APCo and OPCo denied that violations of the reporting requirements occurred and maintain that the proper reporting was done.  In March 2011, APCo and OPCo resolved these issues through the entry of a consent order that included the payment of a $75 thousand civil penalty and certain improvements in the opacity reports.

In March 2010, APCo and OPCo received a request to show cause from the Federal EPA alleging that certain reporting requirements under Superfund and the Emergency Planning and Community Right-to-Know Act had been violated and inviting APCo and OPCo to engage in settlement negotiations.  The request includes a proposed civil penalty of approximately $300 thousand.  Management indicated a willingness to engage in good faith negotiations and provided additional information to representatives of the Federal EPA.  Management has not admitted that any violations occurred or that the amount of the proposed penalty is reasonable.

NUCLEAR CONTINGENCIES – AFFECTING I&M

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission.  I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S.  Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

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 significant turbine damage and a small fire on the electric generator.  This equipment, located in the turbine building, is separate and isolated from the nuclear reactor.  The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period.  The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $408 million.  Management believes that I&M should recover a significant portion of these 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.

I&M maintains insurance through NEIL.  As of June 30, 2011, I&M recorded $60 million on its Condensed Consolidated Balance Sheet representing amounts under NEIL insurance policies.  Through June 30, 2011, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage.
 
NEIL is reviewing claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies.  The review by NEIL includes the timing of the unit’s return to service and whether the return should have occurred earlier reducing the amount received under the accidental outage policy.  The treatment of property damage costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.
 
183

 

OPERATIONAL CONTINGENCIES

Fort Wayne Lease – Affecting I&M

Since 1975 I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expired on February 28, 2010.  I&M negotiated with Fort Wayne to purchase the assets at the end of the lease, but no agreement was reached prior to the end of the lease.

I&M and Fort Wayne reached a settlement agreement.  The agreement, signed in October 2010, is subject to approval by the IURC.  I&M filed a petition with the IURC seeking approval of the agreement, including recovery in rates of payments made to Fort Wayne.  If the agreement is approved, I&M will purchase the remaining leased property and settle claims Fort Wayne asserted.  The agreement provides that I&M will pay Fort Wayne a total of $39 million, inclusive of interest, over 15 years and Fort Wayne will recognize that I&M is the exclusive electricity supplier in the Fort Wayne area.  In April 2011, the Indiana Office of Utility Consumer Counselor (OUCC) filed comments opposing portions of the settlement agreement.  An agreement with the OUCC was reached and hearing before the IURC occurred in June 2011.  IURC approval of the agreement is expected during the third quarter of 2011.  If the agreement is not approved by the IURC, the parties have the right to terminate the agreement and pursue other relief.

Coal Transportation Rate Dispute – Affecting PSO

In 1985, the Burlington Northern Railroad Co. (now BNSF) entered into a coal transportation agreement with PSO.  The agreement contained a base rate subject to adjustment, a rate floor, a reopener provision and an arbitration provision.  In 1992, PSO reopened the pricing provision.  The parties failed to reach an agreement and the matter was arbitrated, with the arbitration panel establishing a lowered rate as of July 1, 1992 (the 1992 Rate) and modifying the rate adjustment formula.  The decision did not mention the rate floor.  From April 1996 through the contract termination in December 2001, the 1992 Rate exceeded the adjusted rate determined according to the decision.  PSO paid the adjusted rate and contended that the panel eliminated the rate floor.  BNSF invoiced at the 1992 Rate and contended that the 1992 Rate was the new rate floor.  PSO terminated the contract by paying a termination fee, as required by the agreement.  BNSF contends that the termination fee should have been calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment of approximately $9.5 million, including interest.

This matter was submitted to an arbitration board.  In April 2006, the arbitration board filed its decision, denying BNSF’s underpayments claim.  PSO filed a request for an order confirming the arbitration award and a request for entry of judgment on the award with the U.S. District Court for the Northern District of Oklahoma.  On July 14, 2006, the U.S. District Court issued an order confirming the arbitration award.  BNSF pursued the matter by filing a Motion to Reconsider, which was granted, but in August 2009, the U.S. District Court upheld the arbitration board’s decision.  BNSF further pursued the decision by appealing to the U.S. Court of Appeals, where in December 2010, the Tenth Circuit Court of Appeals affirmed the U.S. District Court’s order confirming the arbitration award.  PSO then sought and received approval for reimbursement for attorneys’ fees and expenses related to the proceedings at the district court.  In July 2011, the Magistrate for the U.S. District Court also recommended for PSO to be awarded the full amount of its requested appellate attorneys’ fees.
 
5.  ACQUISITION

2010

Valley Electric Membership Corporation – Affecting SWEPCo

In October 2010, SWEPCo purchased certain transmission and distribution assets of Valley Electric Membership Corporation (VEMCO) for approximately $102 million and began serving VEMCO’s 30,000 customers in Louisiana.
 
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6.  BENEFIT PLANS

The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans.  Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan.  The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide medical and life insurance benefits for retired employees.

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost by Registrant Subsidiary for the plans for the three and six months ended June 30, 2011 and 2010:

APCo
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended June 30,
 
Three Months Ended June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
(in thousands)
Service Cost
$
 1,800 
 
$
 3,227 
 
$
 1,246 
 
$
 1,430 
Interest Cost
 
 8,076 
 
 
 8,489 
 
 
 4,867 
 
 
 5,075 
Expected Return on Plan Assets
 
 (10,458)
 
 
 (10,951)
 
 
 (4,496)
 
 
 (4,407)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 287 
 
 
 1,311 
Amortization of Prior Service Cost (Credit)
 
 229 
 
 
 229 
 
 
 (43)
 
 
 - 
Amortization of Net Actuarial Loss
 
 4,144 
 
 
 2,961 
 
 
 1,459 
 
 
 1,353 
Net Periodic Benefit Cost
$
 3,791 
 
$
 3,955 
 
$
 3,320 
 
$
 4,762 

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Six Months Ended June 30,
 
Six Months Ended June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
(in thousands)
Service Cost
$
 3,600 
 
$
 6,454 
 
$
 2,492 
 
$
 2,860 
Interest Cost
 
 16,146 
 
 
 16,978 
 
 
 9,734 
 
 
 10,150 
Expected Return on Plan Assets
 
 (20,916)
 
 
 (21,902)
 
 
 (8,992)
 
 
 (8,813)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 573 
 
 
 2,622 
Amortization of Prior Service Cost (Credit)
 
 458 
 
 
 458 
 
 
 (86)
 
 
 - 
Amortization of Net Actuarial Loss
 
 8,285 
 
 
 5,921 
 
 
 2,914 
 
 
 2,705 
Net Periodic Benefit Cost
$
 7,573 
 
$
 7,909 
 
$
 6,635 
 
$
 9,524 


 
185

 
CSPCo
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended June 30,
 
Three Months Ended June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
(in thousands)
Service Cost
$
 850 
 
$
 1,468 
 
$
 608 
 
$
 690 
Interest Cost
 
 4,302 
 
 
 4,789 
 
 
 2,039 
 
 
 2,179 
Expected Return on Plan Assets
 
 (5,725)
 
 
 (6,589)
 
 
 (1,986)
 
 
 (1,979)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 11 
 
 
 608 
Amortization of Prior Service Cost (Credit)
 
 141 
 
 
 141 
 
 
 (19)
 
 
 - 
Amortization of Net Actuarial Loss
 
 2,210 
 
 
 1,677 
 
 
 578 
 
 
 565 
Net Periodic Benefit Cost
$
 1,778 
 
$
 1,486 
 
$
 1,231 
 
$
 2,063 

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Six Months Ended June 30,
 
Six Months Ended June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
(in thousands)
Service Cost
$
 1,699 
 
$
 2,936 
 
$
 1,217 
 
$
 1,380 
Interest Cost
 
 8,604 
 
 
 9,578 
 
 
 4,079 
 
 
 4,357 
Expected Return on Plan Assets
 
 (11,449)
 
 
 (13,178)
 
 
 (3,973)
 
 
 (3,958)
Amortization of Transition Obligation
 
 - 
 
 
-
 
 
 22 
 
 
 1,216 
Amortization of Prior Service Cost (Credit)
 
 282 
 
 
 282 
 
 
 (37)
 
 
-
Amortization of Net Actuarial Loss
 
 4,420 
 
 
 3,354 
 
 
 1,155 
 
 
 1,130 
Net Periodic Benefit Cost
$
 3,556 
 
$
 2,972 
 
$
 2,463 
 
$
 4,125 

I&M
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended June 30,
 
Three Months Ended June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
(in thousands)
Service Cost
$
 2,365 
 
$
 3,821 
 
$
 1,529 
 
$
 1,688 
Interest Cost
 
 6,934 
 
 
 7,271 
 
 
 3,402 
 
 
 3,541 
Expected Return on Plan Assets
 
 (9,214)
 
 
 (8,760)
 
 
 (3,471)
 
 
 (3,349)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 47 
 
 
 704 
Amortization of Prior Service Cost (Credit)
 
 186 
 
 
 186 
 
 
 (59)
 
 
 - 
Amortization of Net Actuarial Loss
 
 3,538 
 
 
 2,516 
 
 
 892 
 
 
 881 
Net Periodic Benefit Cost
$
 3,809 
 
$
 5,034 
 
$
 2,340 
 
$
 3,465 

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Six Months Ended June 30,
 
Six Months Ended June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
(in thousands)
Service Cost
$
 4,723 
 
$
 7,642 
 
$
 3,059 
 
$
 3,375 
Interest Cost
 
 13,863 
 
 
 14,543 
 
 
 6,805 
 
 
 7,082 
Expected Return on Plan Assets
 
 (18,428)
 
 
 (17,520)
 
 
 (6,943)
 
 
 (6,698)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 94 
 
 
 1,407 
Amortization of Prior Service Cost (Credit)
 
 372 
 
 
 372 
 
 
 (118)
 
 
 - 
Amortization of Net Actuarial Loss
 
 7,072 
 
 
 5,032 
 
 
 1,783 
 
 
 1,763 
Net Periodic Benefit Cost
$
 7,602 
 
$
 10,069 
 
$
 4,680 
 
$
 6,929 

 
186

 
OPCo
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended June 30,
 
Three Months Ended June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
(in thousands)
Service Cost
$
 1,708 
 
$
 2,845 
 
$
 1,348 
 
$
 1,357 
Interest Cost
 
 7,796 
 
 
 8,186 
 
 
 4,334 
 
 
 4,446 
Expected Return on Plan Assets
 
 (10,642)
 
 
 (10,680)
 
 
 (4,141)
 
 
 (4,044)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 27 
 
 
 1,053 
Amortization of Prior Service Cost (Credit)
 
 227 
 
 
 227 
 
 
 (35)
 
 
 - 
Amortization of Net Actuarial Loss
 
 4,004 
 
 
 2,861 
 
 
 1,267 
 
 
 1,154 
Net Periodic Benefit Cost
$
 3,093 
 
$
 3,439 
 
$
 2,800 
 
$
 3,966 

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Six Months Ended June 30,
 
Six Months Ended June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
(in thousands)
Service Cost
$
 3,416 
 
$
 5,691 
 
$
 2,696 
 
$
 2,713 
Interest Cost
 
 15,572 
 
 
 16,372 
 
 
 8,669 
 
 
 8,893 
Expected Return on Plan Assets
 
 (21,284)
 
 
 (21,360)
 
 
 (8,283)
 
 
 (8,089)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 53 
 
 
 2,106 
Amortization of Prior Service Cost (Credit)
 
 454 
 
 
 454 
 
 
 (70)
 
 
 - 
Amortization of Net Actuarial Loss
 
 7,994 
 
 
 5,721 
 
 
 2,494 
 
 
 2,308 
Net Periodic Benefit Cost
$
 6,152 
 
$
 6,878 
 
$
 5,559 
 
$
 7,931 

PSO
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended June 30,
 
Three Months Ended June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
(in thousands)
Service Cost
$
 1,442 
 
$
 1,513 
 
$
 656 
 
$
 704 
Interest Cost
 
 3,338 
 
 
 3,722 
 
 
 1,511 
 
 
 1,590 
Expected Return on Plan Assets
 
 (4,366)
 
 
 (4,935)
 
 
 (1,566)
 
 
 (1,528)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 - 
 
 
 701 
Amortization of Prior Service Credit
 
 (239)
 
 
 (238)
 
 
 (19)
 
 
 - 
Amortization of Net Actuarial Loss
 
 1,700 
 
 
 1,297 
 
 
 388 
 
 
 393 
Net Periodic Benefit Cost
$
 1,875 
 
$
 1,359 
 
$
 970 
 
$
 1,860 

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Six Months Ended June 30,
 
Six Months Ended June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
(in thousands)
Service Cost
$
 2,880 
 
$
 3,026 
 
$
 1,311 
 
$
 1,407 
Interest Cost
 
 6,643 
 
 
 7,444 
 
 
 3,023 
 
 
 3,180 
Expected Return on Plan Assets
 
 (8,732)
 
 
 (9,870)
 
 
 (3,132)
 
 
 (3,055)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,403 
Amortization of Prior Service Credit
 
 (475)
 
 
 (475)
 
 
 (38)
 
 
 - 
Amortization of Net Actuarial Loss
 
 3,378 
 
 
 2,594 
 
 
 776 
 
 
 786 
Net Periodic Benefit Cost
$
 3,694 
 
$
 2,719 
 
$
 1,940 
 
$
 3,721 
 
 
187

 
SWEPCo
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended June 30,
 
Three Months Ended June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
(in thousands)
Service Cost
$
 1,644 
 
$
 1,761 
 
$
 757 
 
$
 777 
Interest Cost
 
 3,348 
 
 
 3,773 
 
 
 1,743 
 
 
 1,735 
Expected Return on Plan Assets
 
 (4,595)
 
 
 (4,872)
 
 
 (1,800)
 
 
 (1,661)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 - 
 
 
 615 
Amortization of Prior Service Cost (Credit)
 
 (200)
 
 
 (199)
 
 
 64 
 
 
 - 
Amortization of Net Actuarial Loss
 
 1,700 
 
 
 1,311 
 
 
 446 
 
 
 428 
Net Periodic Benefit Cost
$
 1,897 
 
$
 1,774 
 
$
 1,210 
 
$
 1,894 

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Six Months Ended June 30,
 
Six Months Ended June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
(in thousands)
Service Cost
$
 3,286 
 
$
 3,523 
 
$
 1,514 
 
$
 1,554 
Interest Cost
 
 6,666 
 
 
 7,547 
 
 
 3,485 
 
 
 3,470 
Expected Return on Plan Assets
 
 (9,190)
 
 
 (9,745)
 
 
 (3,600)
 
 
 (3,323)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,230 
Amortization of Prior Service Cost (Credit)
 
 (398)
 
 
 (398)
 
 
 129 
 
 
 - 
Amortization of Net Actuarial Loss
 
 3,380 
 
 
 2,621 
 
 
 892 
 
 
 856 
Net Periodic Benefit Cost
$
 3,744 
 
$
 3,548 
 
$
 2,420 
 
$
 3,787 

7.  BUSINESS SEGMENTS

The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business.  The Registrant Subsidiaries’ other activities are insignificant.  The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

8.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances.  These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk.  These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates.  AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Trading Strategies

The strategy surrounding the use of derivative instruments for trading purposes focuses on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries.

Risk Management Strategies

The strategy surrounding the use of derivative instruments focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments.  Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and
 
188

 
 
Hedging.”  Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business.  AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio.   For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities.  AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies.  For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.”  The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors.

The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of June 30, 2011 and December 31, 2010:

Notional Volume of Derivative Instruments
June 30, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Primary Risk
 
Unit of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exposure
 
Measure
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
Commodity:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Power
 
MWHs
 
 
 265,492 
 
 
 153,624 
 
 
 158,358 
 
 
 184,179 
 
 
 14 
 
 
 17 
 
Coal
 
Tons
 
 
 8,572 
 
 
 4,602 
 
 
 4,071 
 
 
 16,841 
 
 
 6,473 
 
 
 5,204 
 
Natural Gas
 
MMBtus
 
 
 2,736 
 
 
 1,583 
 
 
 1,623 
 
 
 1,898 
 
 
 24 
 
 
 28 
 
Heating Oil and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
 
Gallons
 
 
 1,248 
 
 
 556 
 
 
 620 
 
 
 926 
 
 
 731 
 
 
 673 
 
Interest Rate
 
USD
 
$
 41,997 
 
$
 24,295 
 
$
 24,896 
 
$
 29,320 
 
$
 283 
 
$
 322 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign Currency
 
USD
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 100,069 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notional Volume of Derivative Instruments
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Primary Risk
 
Unit of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exposure
 
Measure
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
Commodity:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Power
 
MWHs
 
 
 194,217 
 
 
 111,959 
 
 
 117,862 
 
 
 136,657 
 
 
 21 
 
 
 34 
 
Coal
 
Tons
 
 
 11,195 
 
 
 5,550 
 
 
 6,571 
 
 
 23,033 
 
 
 4,936 
 
 
 8,777 
 
Natural Gas
 
MMBtus
 
 
 2,166 
 
 
 1,248 
 
 
 1,302 
 
 
 1,524 
 
 
 15 
 
 
 19 
 
Heating Oil and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
 
Gallons
 
 
 1,054 
 
 
 467 
 
 
 521 
 
 
 776 
 
 
 616 
 
 
 564 
 
Interest Rate
 
USD
 
$
 9,541 
 
$
 5,471 
 
$
 5,732 
 
$
 7,185 
 
$
 609 
 
$
 793 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign Currency
 
USD
 
$
 200,000 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 200,000 
 
$
 189 

Fair Value Hedging Strategies

AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt.  Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate.  Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
 
189

 

Cash Flow Hedging Strategies

AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities.  Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases.  The Registrant Subsidiaries do not hedge all commodity price risk.

The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility.  AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases.  For disclosure purposes, these contracts are included with other hedging activity as “Commodity.”  The Registrant Subsidiaries do not hedge all fuel price risk.

AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure.  Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate.  AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt.  The anticipated fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures.  The Registrant Subsidiaries do not hedge all interest rate exposure.

At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers.  In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar.  The Registrant Subsidiaries do not hedge all foreign currency exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheet at fair value.  The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes.  If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions.  In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due.  Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions.  Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts.  Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles.  Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period.  This is particularly true for longer term contracts.  Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.
 
190

 

According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the June 30, 2011 and December 31, 2010 balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

 
 
 
June 30, 2011
 
December 31, 2010
 
 
 
Cash Collateral
 
Cash Collateral
 
Cash Collateral
 
Cash Collateral
 
 
 
Received
 
Paid
 
Received
 
Paid
 
 
 
Netted Against
 
Netted Against
 
Netted Against
 
Netted Against
 
 
 
Risk Management
 
Risk Management
 
Risk Management
 
Risk Management
Company
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
 
 
(in thousands)
APCo
 
$
 2,825 
 
$
 10,214 
 
$
 1,809 
 
$
 16,229 
CSPCo
 
 
 1,635 
 
 
 5,906 
 
 
 1,042 
 
 
 9,347 
I&M
 
 
 1,676 
 
 
 6,050 
 
 
 1,087 
 
 
 9,757 
OPCo
 
 
 1,960 
 
 
 7,180 
 
 
 1,272 
 
 
 11,561 
PSO
 
 
 1 
 
 
 45 
 
 
 - 
 
 
 44 
SWEPCo
 
 
 1 
 
 
 44 
 
 
 - 
 
 
 72 
 
 
191

 
The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the Condensed Balance Sheets as of June 30, 2011 and December 31, 2010:

Fair Value of Derivative Instruments
June 30, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
178,531 
 
$
3,663 
 
$
 
$
(150,380)
 
$
31,814 
Long-term Risk Management Assets
 
 
73,791 
 
 
672 
 
 
 
 
(42,317)
 
 
32,146 
Total Assets
 
 
252,322 
 
 
4,335 
 
 
 
 
(192,697)
 
 
63,960 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
173,214 
 
 
2,724 
 
 
 
 
(157,436)
 
 
18,502 
Long-term Risk Management Liabilities
 
 
55,201 
 
 
439 
 
 
 
 
(45,312)
 
 
10,328 
Total Liabilities
 
 
228,415 
 
 
3,163 
 
 
 
 
(202,748)
 
 
28,830 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
23,907 
 
$
1,172 
 
$
 
$
10,051 
 
$
35,130 
 
Fair Value of Derivative Instruments
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
267,702 
 
$
1,956 
 
$
11,888 
 
$
(228,304)
 
$
53,242 
Long-term Risk Management Assets
 
 
79,560 
 
 
714 
 
 
 
 
(41,854)
 
 
38,420 
Total Assets
 
 
347,262 
 
 
2,670 
 
 
11,888 
 
 
(270,158)
 
 
91,662 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
262,027 
 
 
2,363 
 
 
 
 
(236,397)
 
 
27,993 
Long-term Risk Management Liabilities
 
 
61,724 
 
 
701 
 
 
 
 
(51,552)
 
 
10,873 
Total Liabilities
 
 
323,751 
 
 
3,064 
 
 
 
 
(287,949)
 
 
38,866 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
23,511 
 
$
(394)
 
$
11,888 
 
$
17,791 
 
$
52,796 

 
192

 
Fair Value of Derivative Instruments
June 30, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CSPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
102,340 
 
$
2,076 
 
$
 
$
(86,065)
 
$
18,351 
Long-term Risk Management Assets
 
 
42,560 
 
 
388 
 
 
 
 
(24,370)
 
 
18,578 
Total Assets
 
 
144,900 
 
 
2,464 
 
 
 
 
(110,435)
 
 
36,929 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
99,241 
 
 
1,572 
 
 
 
 
(90,145)
 
 
10,668 
Long-term Risk Management Liabilities
 
 
31,814 
 
 
251 
 
 
 
 
(26,101)
 
 
5,964 
Total Liabilities
 
 
131,055 
 
 
1,823 
 
 
 
 
(116,246)
 
 
16,632 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
13,845 
 
$
641 
 
$
 
$
5,811 
 
$
20,297 
 
Fair Value of Derivative Instruments
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CSPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
149,886 
 
$
1,164 
 
$
 
$
(127,276)
 
$
23,774 
Long-term Risk Management Assets
 
 
45,413 
 
 
412 
 
 
 
 
(23,736)
 
 
22,089 
Total Assets
 
 
195,299 
 
 
1,576 
 
 
 
 
(151,012)
 
 
45,863 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
146,540 
 
 
1,362 
 
 
 
 
(131,935)
 
 
15,967 
Long-term Risk Management Liabilities
 
 
35,144 
 
 
404 
 
 
 
 
(29,325)
 
 
6,223 
Total Liabilities
 
 
181,684 
 
 
1,766 
 
 
 
 
(161,260)
 
 
22,190 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
13,615 
 
$
(190)
 
$
 
$
10,248 
 
$
23,673 

 
193

 
Fair Value of Derivative Instruments
June 30, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
106,718 
 
$
2,142 
 
$
 
$
(86,519)
 
$
22,341 
Long-term Risk Management Assets
 
 
49,448 
 
 
398 
 
 
 
 
(24,777)
 
 
25,069 
Total Assets
 
 
156,166 
 
 
2,540 
 
 
 
 
(111,296)
 
 
47,410 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
99,960 
 
 
1,614 
 
 
 
 
(90,697)
 
 
10,877 
Long-term Risk Management Liabilities
 
 
32,385 
 
 
259 
 
 
 
 
(26,552)
 
 
6,092 
Total Liabilities
 
 
132,345 
 
 
1,873 
 
 
 
 
(117,249)
 
 
16,969 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
23,821 
 
$
667 
 
$
 
$
5,953 
 
$
30,441 
 
Fair Value of Derivative Instruments
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
162,896 
 
$
1,151 
 
$
 
$
(136,521)
 
$
27,526 
Long-term Risk Management Assets
 
 
56,154 
 
 
429 
 
 
 
 
(25,098)
 
 
31,485 
Total Assets
 
 
219,050 
 
 
1,580 
 
 
 
 
(161,619)
 
 
59,011 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
156,750 
 
 
1,421 
 
 
 
 
(141,386)
 
 
16,785 
Long-term Risk Management Liabilities
 
 
37,039 
 
 
421 
 
 
 
 
(30,930)
 
 
6,530 
Total Liabilities
 
 
193,789 
 
 
1,842 
 
 
 
 
(172,316)
 
 
23,315 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
25,261 
 
$
(262)
 
$
 
$
10,697 
 
$
35,696 

 
194

 
Fair Value of Derivative Instruments
June 30, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
153,202 
 
$
2,558 
 
$
 
$
(133,245)
 
$
22,515 
Long-term Risk Management Assets
 
 
55,377 
 
 
467 
 
 
 
 
(32,864)
 
 
22,980 
Total Assets
 
 
208,579 
 
 
3,025 
 
 
 
 
(166,109)
 
 
45,495 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
150,203 
 
 
1,890 
 
 
 
 
(138,234)
 
 
13,859 
Long-term Risk Management Liabilities
 
 
42,177 
 
 
305 
 
 
 
 
(34,942)
 
 
7,540 
Total Liabilities
 
 
192,380 
 
 
2,195 
 
 
 
 
(173,176)
 
 
21,399 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
16,199 
 
$
830 
 
$
 
$
7,067 
 
$
24,096 
 
Fair Value of Derivative Instruments
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
262,751 
 
$
1,316 
 
$
 
$
(233,294)
 
$
30,773 
Long-term Risk Management Assets
 
 
63,533 
 
 
503 
 
 
 
 
(36,024)
 
 
28,012 
Total Assets
 
 
326,284 
 
 
1,819 
 
 
 
 
(269,318)
 
 
58,785 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
259,635 
 
 
1,663 
 
 
 
 
(239,132)
 
 
22,166 
Long-term Risk Management Liabilities
 
 
50,757 
 
 
493 
 
 
 
 
(42,847)
 
 
8,403 
Total Liabilities
 
 
310,392 
 
 
2,156 
 
 
 
 
(281,979)
 
 
30,569 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
15,892 
 
$
(337)
 
$
 
$
12,661 
 
$
28,216 

 
195

 
Fair Value of Derivative Instruments
June 30, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
12,380 
 
$
193 
 
$
 
$
(12,083)
 
$
490 
Long-term Risk Management Assets
 
 
2,155 
 
 
 
 
 
 
(1,479)
 
 
685 
Total Assets
 
 
14,535 
 
 
202 
 
 
 
 
(13,562)
 
 
1,175 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
12,989 
 
 
11 
 
 
 
 
(12,124)
 
 
876 
Long-term Risk Management Liabilities
 
 
1,633 
 
 
 
 
 
 
(1,482)
 
 
159 
Total Liabilities
 
 
14,622 
 
 
19 
 
 
 
 
(13,606)
 
 
1,035 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
(87)
 
$
183 
 
$
 
$
44 
 
$
140 
 
Fair Value of Derivative Instruments
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
19,174 
 
$
134 
 
$
13,558 
 
$
(18,641)
 
$
14,225 
Long-term Risk Management Assets
 
 
1,944 
 
 
 
 
 
 
(1,692)
 
 
252 
Total Assets
 
 
21,118 
 
 
134 
 
 
13,558 
 
 
(20,333)
 
 
14,477 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
19,607 
 
 
 
 
 
 
(18,685)
 
 
922 
Long-term Risk Management Liabilities
 
 
1,889 
 
 
 
 
 
 
(1,692)
 
 
197 
Total Liabilities
 
 
21,496 
 
 
 
 
 
 
(20,377)
 
 
1,119 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
(378)
 
$
134 
 
$
13,558 
 
$
44 
 
$
13,358 

 
196

 
Fair Value of Derivative Instruments
June 30, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
(in thousands)
Current Risk Management Assets
 
$
12,172 
 
$
178 
 
$
1,217 
 
$
(11,954)
 
$
1,613 
Long-term Risk Management Assets
 
 
1,730 
 
 
 
 
10 
 
 
(1,452)
 
 
296 
Total Assets
 
 
13,902 
 
 
186 
 
 
1,227 
 
 
(13,406)
 
 
1,909 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
13,362 
 
 
 
 
 
 
(11,993)
 
 
1,378 
Long-term Risk Management Liabilities
 
 
1,605 
 
 
 
 
 
 
(1,456)
 
 
156 
Total Liabilities
 
 
14,967 
 
 
16 
 
 
 
 
(13,449)
 
 
1,534 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
(1,065)
 
$
170 
 
$
1,227 
 
$
43 
 
$
375 
 
Fair Value of Derivative Instruments
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
(in thousands)
Current Risk Management Assets
 
$
33,284 
 
$
123 
 
$
 
$
(32,198)
 
$
1,209 
Long-term Risk Management Assets
 
 
3,346 
 
 
 
 
 
 
(2,913)
 
 
438 
Total Assets
 
 
36,630 
 
 
123 
 
 
 
 
(35,111)
 
 
1,647 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
36,338 
 
 
 
 
 
 
(32,271)
 
 
4,067 
Long-term Risk Management Liabilities
 
 
3,250 
 
 
 
 
 
 
(2,912)
 
 
338 
Total Liabilities
 
 
39,588 
 
 
 
 
 
 
(35,183)
 
 
4,405 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
(2,958)
 
$
123 
 
$
 
$
72 
 
$
(2,758)

(a) Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the Condensed Balance Sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."
(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."  Amounts also include dedesignated risk management contracts.
 
 
197

 
The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and six months ended June 30, 2011 and 2010:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2011
 
Location of Gain (Loss)
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
(in thousands)
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
$
 883 
 
$
 5,134 
 
$
 3,702 
 
$
 6,430 
 
$
 539 
 
$
 403 
Sales to AEP Affiliates
 
 
 13 
 
 
 6 
 
 
 6 
 
 
 7 
 
 
 (1)
 
 
 (1)
Regulatory Assets (a)
 
 
 (150)
 
 
 (2,183)
 
 
 (1,018)
 
 
 (2,420)
 
 
 644 
 
 
 404 
Regulatory Liabilities (a)
 
 
 4,142 
 
 
 - 
 
 
 (1,077)
 
 
 - 
 
 
 461 
 
 
 692 
Total Gain (Loss) on Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
$
 4,888 
 
$
 2,957 
 
$
 1,613 
 
$
 4,017 
 
$
 1,643 
 
$
 1,498 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2010
 
Location of Gain (Loss)
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
(in thousands)
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
$
 (1,693)
 
$
 3,469 
 
$
 2,503 
 
$
 2,010 
 
$
 347 
 
$
 613 
Sales to AEP Affiliates
 
 
 786 
 
 
 113 
 
 
 102 
 
 
 2,156 
 
 
 (121)
 
 
 (229)
Regulatory Assets (a)
 
 
 (1,046)
 
 
 (5,225)
 
 
 (2,238)
 
 
 (5,754)
 
 
 (25)
 
 
 120 
Regulatory Liabilities (a)
 
 
 (834)
 
 
 - 
 
 
 (4,393)
 
 
 - 
 
 
 126 
 
 
 1,524 
Total Gain (Loss) on Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
$
 (2,787)
 
$
 (1,643)
 
$
 (4,026)
 
$
 (1,588)
 
$
 327 
 
$
 2,028 

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Six Months Ended June 30, 2011
 
Location of Gain (Loss)
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
$
 2,699 
 
$
 9,924 
 
$
 9,117 
 
$
 12,230 
 
$
 658 
 
$
 526 
Sales to AEP Affiliates
 
 
 33 
 
 
 19 
 
 
 23 
 
 
 26 
 
 
 - 
 
 
 - 
Regulatory Assets (a)
 
 
 223 
 
 
 (2,095)
 
 
 115 
 
 
 (2,113)
 
 
 276 
 
 
 2,046 
Regulatory Liabilities (a)
 
 
 10,896 
 
 
 - 
 
 
 (1,664)
 
 
 (105)
 
 
 853 
 
 
 1,032 
Total Gain (Loss) on Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
$
 13,851 
 
$
 7,848 
 
$
 7,591 
 
$
 10,038 
 
$
 1,787 
 
$
 3,604 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Six Months Ended June 30, 2010
 
Location of Gain (Loss)
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
$
 2,480 
 
$
 13,076 
 
$
 9,388 
 
$
 12,231 
 
$
 1,030 
 
$
 1,402 
Sales to AEP Affiliates
 
 
 (1,575)
 
 
 (1,449)
 
 
 (1,341)
 
 
 2,409 
 
 
 (297)
 
 
 (538)
Regulatory Assets (a)
 
 
 - 
 
 
 (1,544)
 
 
 - 
 
 
 (1,690)
 
 
 306 
 
 
 73 
Regulatory Liabilities (a)
 
 
 15,147 
 
 
 - 
 
 
 8,461 
 
 
 29 
 
 
 2,764 
 
 
 513 
Total Gain (Loss) on Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
$
 16,052 
 
$
 10,083 
 
$
 16,508 
 
$
 12,979 
 
$
 3,803 
 
$
 1,450 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)  Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current  or noncurrent on the balance sheet.

 
198

 
Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.”  Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the Condensed Statements of Income on an accrual basis.

The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship.  Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes.  Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the Condensed Statements of Income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the Condensed Statements of Income depending on the relevant facts and circumstances.  However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

Accounting for Fair Value Hedging Strategies

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change.

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the Condensed Statements of Income.  During the three and six months ended June 30, 2011 and 2010, the Registrant Subsidiaries did not employ any fair value hedging strategies.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets until the period the hedged item affects Net Income.  The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal, natural gas and heating oil and gasoline designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the Condensed Statements of Income, or in Regulatory Assets or Regulatory Liabilities on the Condensed Balance Sheets, depending on the specific nature of the risk being hedged.  During the three and six months ended June 30, 2011 and 2010, APCo, CSPCo, I&M and OPCo designated commodity derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the Condensed Statements of Income.  During the three and six months ended June 30, 2011 and 2010, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges.
 
199

 
 
The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur.  During the three and six months ended June 30, 2011, SWEPCo designated interest rate derivatives as cash flow hedges.  During the six months ended June 30, 2011, APCo and PSO designated interest rate derivatives as cash flow hedges.  During the three and six months ended June 30, 2010, APCo designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets into Depreciation and Amortization expense on the Condensed Statements of Income over the depreciable lives of the fixed assets that were designated as the hedged items in qualifying foreign currency hedging relationships.  During the three and six months ended June 30, 2011 and 2010, SWEPCo designated foreign currency derivatives as cash flow hedges.

During the three and six months ended June 30, 2011 and 2010, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.
 
200

 
 
The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2011 and 2010.  All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2011
 
Commodity Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance in AOCI as of March 31, 2011
 
$
 238 
 
$
 79 
 
$
 101 
 
$
 190 
 
$
 264 
 
$
 244 
Changes in Fair Value Recognized in AOCI
 
 
 (55)
 
 
 (24)
 
 
 (25)
 
 
 (40)
 
 
 (32)
 
 
 (26)
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission, and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 175 
 
 
 482 
 
 
 396 
 
 
 578 
 
 
 - 
 
 
 - 
 
 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Purchased Electricity for Resale
 
 
 (41)
 
 
 (112)
 
 
 (92)
 
 
 (134)
 
 
 - 
 
 
 - 
 
 
Other Operation Expense
 
 
 (31)
 
 
 (26)
 
 
 (28)
 
 
 (34)
 
 
 (34)
 
 
 (33)
 
 
Maintenance Expense
 
 
 (65)
 
 
 (18)
 
 
 (22)
 
 
 (33)
 
 
 (22)
 
 
 (24)
 
 
Property, Plant and Equipment
 
 
 (57)
 
 
 (23)
 
 
 (28)
 
 
 (48)
 
 
 (36)
 
 
 (29)
 
 
Regulatory Assets (a)
 
 
 505 
 
 
 - 
 
 
 76 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Regulatory Liabilities (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Balance in AOCI as of June 30, 2011
 
$
 669 
 
$
 358 
 
$
 378 
 
$
 479 
 
$
 140 
 
$
 132 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and Foreign Currency
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Balance in AOCI as of March 31, 2011
 
$
 217 
 
$
 - 
 
$
 (8,255)
 
$
 10,473 
 
$
 7,787 
 
$
 (4,058)
Changes in Fair Value Recognized in AOCI
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 794 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1 
 
 
 - 
 
 
 - 
 
 
Other Operation Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Interest Expense
 
 
 269 
 
 
 - 
 
 
 251 
 
 
 (341)
 
 
 (189)
 
 
 207 
Balance in AOCI as of June 30, 2011
 
$
 486 
 
$
 - 
 
$
 (8,004)
 
$
 10,133 
 
$
 7,598 
 
$
 (3,057)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Balance in AOCI as of March 31, 2011
 
$
 455 
 
$
 79 
 
$
 (8,154)
 
$
 10,663 
 
$
 8,051 
 
$
 (3,814)
Changes in Fair Value Recognized in AOCI
 
 
 (55)
 
 
 (24)
 
 
 (25)
 
 
 (40)
 
 
 (32)
 
 
 768 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission, and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 175 
 
 
 482 
 
 
 396 
 
 
 578 
 
 
 - 
 
 
 - 
 
 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Purchased Electricity for Resale
 
 
 (41)
 
 
 (112)
 
 
 (92)
 
 
 (134)
 
 
 - 
 
 
 - 
 
 
Other Operation Expense
 
 
 (31)
 
 
 (26)
 
 
 (28)
 
 
 (34)
 
 
 (34)
 
 
 (33)
 
 
Maintenance Expense
 
 
 (65)
 
 
 (18)
 
 
 (22)
 
 
 (33)
 
 
 (22)
 
 
 (24)
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1 
 
 
 - 
 
 
 - 
 
 
Interest Expense
 
 
 269 
 
 
 - 
 
 
 251 
 
 
 (341)
 
 
 (189)
 
 
 207 
 
 
Property, Plant and Equipment
 
 
 (57)
 
 
 (23)
 
 
 (28)
 
 
 (48)
 
 
 (36)
 
 
 (29)
 
 
Regulatory Assets (a)
 
 
 505 
 
 
 - 
 
 
 76 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Regulatory Liabilities (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Balance in AOCI as of June 30, 2011
 
$
 1,155 
 
$
 358 
 
$
 (7,626)
 
$
 10,612 
 
$
 7,738 
 
$
 (2,925)

 
201

 
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2010
 
Commodity Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance in AOCI as of March 31, 2010
 
$
 (2,451)
 
$
 (1,407)
 
$
 (1,418)
 
$
 (1,543)
 
$
 (8)
 
$
 100 
Changes in Fair Value Recognized in AOCI
 
 
 642 
 
 
 380 
 
 
 388 
 
 
 370 
 
 
 (191)
 
 
 (99)
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission, and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 31 
 
 
 79 
 
 
 66 
 
 
 91 
 
 
 - 
 
 
 - 
 
 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (4)
 
 
 150 
 
 
 - 
 
 
Purchased Electricity for Resale
 
 
 65 
 
 
 168 
 
 
 139 
 
 
 193 
 
 
 - 
 
 
 - 
 
 
Other Operation Expense
 
 
 (18)
 
 
 (11)
 
 
 (11)
 
 
 (15)
 
 
 (13)
 
 
 (16)
 
 
Maintenance Expense
 
 
 (22)
 
 
 (6)
 
 
 (9)
 
 
 (11)
 
 
 (8)
 
 
 (8)
 
 
Property, Plant and Equipment
 
 
 (24)
 
 
 (10)
 
 
 (12)
 
 
 (17)
 
 
 (14)
 
 
 (10)
 
 
Regulatory Assets (a)
 
 
 340 
 
 
 - 
 
 
 44 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Regulatory Liabilities (a)
 
 
-
 
 
 - 
 
 
 - 
 
 
 (5)
 
 
 - 
 
 
 - 
Balance in AOCI as of June 30, 2010
 
$
 (1,437)
 
$
 (807)
 
$
 (813)
 
$
 (941)
 
$
 (84)
 
$
 (33)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and Foreign Currency
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Balance in AOCI as of March 31, 2010
 
$
 (6,488)
 
$
 - 
 
$
 (9,262)
 
$
 11,832 
 
$
 (475)
 
$
 (4,947)
Changes in Fair Value Recognized in AOCI
 
 
 (2,229)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (96)
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1 
 
 
 - 
 
 
 - 
 
 
Other Operation Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 24 
 
 
Interest Expense
 
 
 419 
 
 
 - 
 
 
 251 
 
 
 (341)
 
 
 32 
 
 
 207 
Balance in AOCI as of June 30, 2010
 
$
 (8,298)
 
$
 - 
 
$
 (9,011)
 
$
 11,492 
 
$
 (443)
 
$
 (4,812)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Balance in AOCI as of March 31, 2010
 
$
 (8,939)
 
$
 (1,407)
 
$
 (10,680)
 
$
 10,289 
 
$
 (483)
 
$
 (4,847)
Changes in Fair Value Recognized in AOCI
 
 
 (1,587)
 
 
 380 
 
 
 388 
 
 
 370 
 
 
 (191)
 
 
 (195)
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission, and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 31 
 
 
 79 
 
 
 66 
 
 
 91 
 
 
 - 
 
 
 - 
 
 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (4)
 
 
 150 
 
 
 - 
 
 
Purchased Electricity for Resale
 
 
 65 
 
 
 168 
 
 
 139 
 
 
 193 
 
 
 - 
 
 
 - 
 
 
Other Operation Expense
 
 
 (18)
 
 
 (11)
 
 
 (11)
 
 
 (15)
 
 
 (13)
 
 
 8 
 
 
Maintenance Expense
 
 
 (22)
 
 
 (6)
 
 
 (9)
 
 
 (11)
 
 
 (8)
 
 
 (8)
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1 
 
 
 - 
 
 
 - 
 
 
Interest Expense
 
 
 419 
 
 
 - 
 
 
 251 
 
 
 (341)
 
 
 32 
 
 
 207 
 
 
Property, Plant and Equipment
 
 
 (24)
 
 
 (10)
 
 
 (12)
 
 
 (17)
 
 
 (14)
 
 
 (10)
 
 
Regulatory Assets (a)
 
 
 340 
 
 
 - 
 
 
 44 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Regulatory Liabilities (a)
 
 
-
 
 
 - 
 
 
 - 
 
 
 (5)
 
 
 - 
 
 
 - 
Balance in AOCI as of June 30, 2010
 
$
 (9,735)
 
$
 (807)
 
$
 (9,824)
 
$
 10,551 
 
$
 (527)
 
$
 (4,845)

 
202

 
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2011
 
Commodity Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance in AOCI as of December 31, 2010
 
$
 (273)
 
$
 (134)
 
$
 (178)
 
$
 (230)
 
$
 88 
 
$
 82 
Changes in Fair Value Recognized in AOCI
 
 
 123 
 
 
 (12)
 
 
 53 
 
 
 155 
 
 
 180 
 
 
 168 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission, and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 171 
 
 
 470 
 
 
 386 
 
 
 564 
 
 
 - 
 
 
 - 
 
 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Purchased Electricity for Resale
 
 
 46 
 
 
 125 
 
 
 102 
 
 
 150 
 
 
 - 
 
 
 - 
 
 
Other Operation Expense
 
 
 (44)
 
 
 (35)
 
 
 (37)
 
 
 (48)
 
 
 (47)
 
 
 (46)
 
 
Maintenance Expense
 
 
 (90)
 
 
 (24)
 
 
 (32)
 
 
 (46)
 
 
 (29)
 
 
 (32)
 
 
Property, Plant and Equipment
 
 
 (80)
 
 
 (32)
 
 
 (39)
 
 
 (66)
 
 
 (52)
 
 
 (40)
 
 
Regulatory Assets (a)
 
 
 816 
 
 
 - 
 
 
 123 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Regulatory Liabilities (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Balance in AOCI as of June 30, 2011
 
$
 669 
 
$
 358 
 
$
 378 
 
$
 479 
 
$
 140 
 
$
 132 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and Foreign Currency
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Balance in AOCI as of December 31, 2010
 
$
 217 
 
$
 - 
 
$
 (8,507)
 
$
 10,813 
 
$
 8,406 
 
$
 (4,272)
Changes in Fair Value Recognized in AOCI
 
 
 (373)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (476)
 
 
 801 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 2 
 
 
 - 
 
 
 - 
 
 
Other Operation Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Interest Expense
 
 
 642 
 
 
 - 
 
 
 503 
 
 
 (682)
 
 
 (332)
 
 
 414 
Balance in AOCI as of June 30, 2011
 
$
 486 
 
$
 - 
 
$
 (8,004)
 
$
 10,133 
 
$
 7,598 
 
$
 (3,057)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Balance in AOCI as of December 31, 2010
 
$
 (56)
 
$
 (134)
 
$
 (8,685)
 
$
 10,583 
 
$
 8,494 
 
$
 (4,190)
Changes in Fair Value Recognized in AOCI
 
 
 (250)
 
 
 (12)
 
 
 53 
 
 
 155 
 
 
 (296)
 
 
 969 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission, and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 171 
 
 
 470 
 
 
 386 
 
 
 564 
 
 
 - 
 
 
 - 
 
 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Purchased Electricity for Resale
 
 
 46 
 
 
 125 
 
 
 102 
 
 
 150 
 
 
 - 
 
 
 - 
 
 
Other Operation Expense
 
 
 (44)
 
 
 (35)
 
 
 (37)
 
 
 (48)
 
 
 (47)
 
 
 (46)
 
 
Maintenance Expense
 
 
 (90)
 
 
 (24)
 
 
 (32)
 
 
 (46)
 
 
 (29)
 
 
 (32)
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 2 
 
 
 - 
 
 
 - 
 
 
Interest Expense
 
 
 642 
 
 
 - 
 
 
 503 
 
 
 (682)
 
 
 (332)
 
 
 414 
 
 
Property, Plant and Equipment
 
 
 (80)
 
 
 (32)
 
 
 (39)
 
 
 (66)
 
 
 (52)
 
 
 (40)
 
 
Regulatory Assets (a)
 
 
 816 
 
 
 - 
 
 
 123 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Regulatory Liabilities (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Balance in AOCI as of June 30, 2011
 
$
 1,155 
 
$
 358 
 
$
 (7,626)
 
$
 10,612 
 
$
 7,738 
 
$
 (2,925)

 
203

 
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2010
 
Commodity Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance in AOCI as of December 31, 2009
 
$
 (743)
 
$
 (376)
 
$
 (382)
 
$
 (366)
 
$
 (78)
 
$
 112 
Changes in Fair Value Recognized in AOCI
 
 
 (1,857)
 
 
 (1,077)
 
 
 (1,083)
 
 
 (1,300)
 
 
 (105)
 
 
 (96)
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission, and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 57 
 
 
 144 
 
 
 120 
 
 
 167 
 
 
 - 
 
 
 - 
 
 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (13)
 
 
 150 
 
 
 - 
 
 
Purchased Electricity for Resale
 
 
 211 
 
 
 550 
 
 
 455 
 
 
 633 
 
 
 - 
 
 
 - 
 
 
Other Operation Expense
 
 
 (24)
 
 
 (19)
 
 
 (17)
 
 
 (20)
 
 
 (19)
 
 
 (23)
 
 
Maintenance Expense
 
 
 (36)
 
 
 (12)
 
 
 (14)
 
 
 (15)
 
 
 (12)
 
 
 (12)
 
 
Property, Plant and Equipment
 
 
 (33)
 
 
 (17)
 
 
 (17)
 
 
 (22)
 
 
 (20)
 
 
 (14)
 
 
Regulatory Assets (a)
 
 
 988 
 
 
 - 
 
 
 125 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Regulatory Liabilities (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (5)
 
 
 - 
 
 
 - 
Balance in AOCI as of June 30, 2010
 
$
 (1,437)
 
$
 (807)
 
$
 (813)
 
$
 (941)
 
$
 (84)
 
$
 (33)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and Foreign Currency
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Balance in AOCI as of December 31, 2009
 
$
 (6,450)
 
$
 - 
 
$
 (9,514)
 
$
 12,172 
 
$
 (521)
 
$
 (5,047)
Changes in Fair Value Recognized in AOCI
 
 
 (2,685)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (203)
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 2 
 
 
 - 
 
 
 - 
 
 
Other Operation Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 24 
 
 
Interest Expense
 
 
 837 
 
 
 - 
 
 
 503 
 
 
 (682)
 
 
 78 
 
 
 414 
Balance in AOCI as of June 30, 2010
 
$
 (8,298)
 
$
 - 
 
$
 (9,011)
 
$
 11,492 
 
$
 (443)
 
$
 (4,812)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Balance in AOCI as of December 31, 2009
 
$
 (7,193)
 
$
 (376)
 
$
 (9,896)
 
$
 11,806 
 
$
 (599)
 
$
 (4,935)
Changes in Fair Value Recognized in AOCI
 
 
 (4,542)
 
 
 (1,077)
 
 
 (1,083)
 
 
 (1,300)
 
 
 (105)
 
 
 (299)
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission, and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 57 
 
 
 144 
 
 
 120 
 
 
 167 
 
 
 - 
 
 
 - 
 
 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (13)
 
 
 150 
 
 
 - 
 
 
Purchased Electricity for Resale
 
 
 211 
 
 
 550 
 
 
 455 
 
 
 633 
 
 
 - 
 
 
 - 
 
 
Other Operation Expense
 
 
 (24)
 
 
 (19)
 
 
 (17)
 
 
 (20)
 
 
 (19)
 
 
 1 
 
 
Maintenance Expense
 
 
 (36)
 
 
 (12)
 
 
 (14)
 
 
 (15)
 
 
 (12)
 
 
 (12)
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 2 
 
 
 - 
 
 
 - 
 
 
Interest Expense
 
 
 837 
 
 
 - 
 
 
 503 
 
 
 (682)
 
 
 78 
 
 
 414 
 
 
Property, Plant and Equipment
 
 
 (33)
 
 
 (17)
 
 
 (17)
 
 
 (22)
 
 
 (20)
 
 
 (14)
 
 
Regulatory Assets (a)
 
 
 988 
 
 
 - 
 
 
 125 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Regulatory Liabilities (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (5)
 
 
 - 
 
 
 - 
Balance in AOCI as of June 30, 2010
 
$
 (9,735)
 
$
 (807)
 
$
 (9,824)
 
$
 10,551 
 
$
 (527)
 
$
 (4,845)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
 
Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the Condensed Balance Sheets.
 
 
204

 
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets at June 30, 2011 and December 31, 2010 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
June 30, 2011
 
 
 
 
Hedging Assets (a)
 
Hedging Liabilities (a)
 
AOCI Gain (Loss) Net of Tax
 
 
 
 
 
Interest Rate
 
 
 
Interest Rate
 
 
 
Interest Rate
 
 
 
 
 
and Foreign
 
 
 
and Foreign
 
 
 
and Foreign
Company
 
Commodity
 
Currency
 
Commodity
 
Currency
 
Commodity
 
Currency
 
 
 
(in thousands)
APCo
 
$
 1,693 
 
$
 - 
 
$
 521 
 
$
 - 
 
$
 669 
 
$
 486 
CSPCo
 
 
 938 
 
 
 - 
 
 
 297 
 
 
 - 
 
 
 358 
 
 
 - 
I&M
 
 
 974 
 
 
 - 
 
 
 307 
 
 
 - 
 
 
 378 
 
 
 (8,004)
OPCo
 
 
 1,192 
 
 
 - 
 
 
 362 
 
 
 - 
 
 
 479 
 
 
 10,133 
PSO
 
 
 195 
 
 
 - 
 
 
 12 
 
 
 - 
 
 
 140 
 
 
 7,598 
SWEPCo
 
 
 181 
 
 
 1,227 
 
 
 11 
 
 
 - 
 
 
 132 
 
 
 (3,057)

 
 
 
Expected to be Reclassified to
 
 
 
 
 
 
Net Income During the Next
 
 
 
 
 
 
Twelve Months
 
 
 
 
 
 
 
 
 
 
Maximum Term for
 
 
 
 
 
Interest Rate
 
Exposure to
 
 
 
 
 
and Foreign
 
Variability of Future
Company
 
Commodity
 
Currency
 
Cash Flows
 
 
 
(in thousands)
 
(in months)
APCo
 
$
 507 
 
$
 (1,076)
 
 
 35 
CSPCo
 
 
 264 
 
 
 - 
 
 
 35 
I&M
 
 
 280 
 
 
 (750)
 
 
 35 
OPCo
 
 
 365 
 
 
 1,359 
 
 
 35 
PSO
 
 
 140 
 
 
 759 
 
 
 18 
SWEPCo
 
 
 129 
 
 
 (766)
 
 
 18 


 
205

 
Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 2010
 
 
 
 
Hedging Assets (a)
 
Hedging Liabilities (a)
 
AOCI Gain (Loss) Net of Tax
 
 
 
 
 
Interest Rate
 
 
 
Interest Rate
 
 
 
Interest Rate
 
 
 
 
 
and Foreign
 
 
 
and Foreign
 
 
 
and Foreign
Company
 
Commodity
 
Currency
 
Commodity
 
Currency
 
Commodity
 
Currency
 
 
 
(in thousands)
APCo
 
$
 333 
 
$
 11,888 
 
$
 727 
 
$
 - 
 
$
 (273)
 
$
 217 
CSPCo
 
 
 229 
 
 
 - 
 
 
 419 
 
 
 - 
 
 
 (134)
 
 
 - 
I&M
 
 
 175 
 
 
 - 
 
 
 437 
 
 
 - 
 
 
 (178)
 
 
 (8,507)
OPCo
 
 
 174 
 
 
 - 
 
 
 511 
 
 
 - 
 
 
 (230)
 
 
 10,813 
PSO
 
 
 134 
 
 
 13,558 
 
 
 - 
 
 
 - 
 
 
 88 
 
 
 8,406 
SWEPCo
 
 
 123 
 
 
 5 
 
 
 - 
 
 
 - 
 
 
 82 
 
 
 (4,272)

 
 
 
Expected to be Reclassified to
 
 
 
 
Net Income During the Next
 
 
 
 
Twelve Months
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
and Foreign
 
Company
 
Commodity
 
Currency
 
 
 
 
(in thousands)
 
APCo
 
$
 (280)
 
$
 (1,173)
 
CSPCo
 
 
 (137)
 
 
 - 
 
I&M
 
 
 (184)
 
 
 (955)
 
OPCo
 
 
 (236)
 
 
 1,359 
 
PSO
 
 
 88 
 
 
 735 
 
SWEPCo
 
 
 82 
 
 
 (829)
 

(a)
Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the Condensed Balance Sheets.

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

Credit Risk

AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements which may include collateral requirements.  These master agreements facilitate the netting of cash flows associated with a single counterparty.  Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk.  The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold.  The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy.  In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
 
206

 

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade.  The amount of collateral required fluctuates based on market prices and total exposure.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts.  Management does not anticipate a downgrade below investment grade.  The following tables represent: (a) the Registrant Subsidiaries’ aggregate fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of June 30, 2011 and December 31, 2010:

 
 
 
June 30, 2011
 
 
 
Liabilities for
 
Amount of Collateral the
 
Amount
 
 
 
Derivative Contracts
 
Registrant Subsidiaries
 
Attributable to
 
 
 
with Credit
 
Would Have Been
 
RTO and ISO
Company
 
Downgrade Triggers
 
Required to Post
 
Activities
 
 
 
(in thousands)
APCo
 
$
 9,515 
 
$
 7,366 
 
$
 7,366 
CSPCo
 
 
 5,506 
 
 
 4,262 
 
 
 4,262 
I&M
 
 
 5,644 
 
 
 4,370 
 
 
 4,370 
OPCo
 
 
 6,601 
 
 
 5,110 
 
 
 5,110 
PSO
 
 
 - 
 
 
 3,196 
 
 
 2,913 
SWEPCo
 
 
 - 
 
 
 3,830 
 
 
 3,490 

 
 
 
December 31, 2010
 
 
 
Liabilities for
 
Amount of Collateral the
 
Amount
 
 
 
Derivative Contracts
 
Registrant Subsidiaries
 
Attributable to
 
 
 
with Credit
 
Would Have Been
 
RTO and ISO
Company
 
Downgrade Triggers
 
Required to Post
 
Activities
 
 
 
(in thousands)
APCo
 
$
 6,594 
 
$
 12,607 
 
$
 12,574 
CSPCo
 
 
 3,801 
 
 
 7,267 
 
 
 7,248 
I&M
 
 
 3,965 
 
 
 7,581 
 
 
 7,561 
OPCo
 
 
 4,640 
 
 
 8,871 
 
 
 8,847 
PSO
 
 
 16 
 
 
 1,785 
 
 
 1,385 
SWEPCo
 
 
 19 
 
 
 2,139 
 
 
 1,659 

As of June 30, 2011 and December 31, 2010, the Registrant Subsidiaries were not required to post any collateral.
 
207

 

In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts.  Management does not anticipate a non-performance event under these provisions.  The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of June 30, 2011 and December 31, 2010:

 
 
 
June 30, 2011
 
 
 
Liabilities for
 
 
 
Additional
 
 
 
Contracts with Cross
 
 
 
Settlement
 
 
 
Default Provisions
 
 
 
Liability if Cross
 
 
 
Prior to Contractual
 
Amount of Cash
 
Default Provision
Company
 
Netting Arrangements
 
Collateral Posted
 
is Triggered
 
 
 
(in thousands)
APCo
 
$
 63,340 
 
$
 3,006 
 
$
 18,543 
CSPCo
 
 
 36,650 
 
 
 1,739 
 
 
 10,729 
I&M
 
 
 37,574 
 
 
 1,783 
 
 
 10,999 
OPCo
 
 
 43,952 
 
 
 2,085 
 
 
 12,875 
PSO
 
 
 31 
 
 
 - 
 
 
 19 
SWEPCo
 
 
 36 
 
 
 - 
 
 
 21 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2010
 
 
 
Liabilities for
 
 
 
Additional
 
 
 
Contracts with Cross
 
 
 
Settlement
 
 
 
Default Provisions
 
 
 
Liability if Cross
 
 
 
Prior to Contractual
 
Amount of Cash
 
Default Provision
Company
 
Netting Arrangements
 
Collateral Posted
 
is Triggered
 
 
 
(in thousands)
APCo
 
$
 76,810 
 
$
 6,637 
 
$
 23,748 
CSPCo
 
 
 44,277 
 
 
 3,826 
 
 
 13,689 
I&M
 
 
 46,188 
 
 
 3,991 
 
 
 14,280 
OPCo
 
 
 54,066 
 
 
 4,670 
 
 
 16,731 
PSO
 
 
 60 
 
 
 - 
 
 
 28 
SWEPCo
 
 
 75 
 
 
 - 
 
 
 37 

9.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.
 
208

 
 
For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which are non-binding in nature but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, the quoted bid and ask prices are averaged.  In certain circumstances, a broker quote may be discarded if it is a clear outlier.  Management uses a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.

AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts.  AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value.  AEP’s investment managers perform their own valuation testing to verify the fair values of the securities.  AEP receives audit reports of the trustee’s operating controls and valuation processes.  The trustee uses multiple pricing vendors for the assets held in the trusts.

Assets in the nuclear trusts and Other Cash Deposits are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.  Fixed income securities do not trade on an exchange and do not have an official closing price.  Pricing vendors calculate bond valuations using financial models and matrices.  Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data.  Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data and economic events.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

Items classified as Level 2 are primarily investments in individual fixed income securities.  These fixed income securities are valued using models with input data as follows:

 
 
 
Type of Fixed Income Security
 
 
 
United States
 
 
 
State and Local
Type of Input
 
Government
 
Corporate Debt
 
Government
 
 
 
 
 
 
 
 
Benchmark Yields
 
X
 
X
 
X
Broker Quotes
 
X
 
X
 
X
Discount Margins
 
X
 
X
 
 
Treasury Market Update
 
X
 
 
 
 
Base Spread
 
X
 
X
 
X
Corporate Actions
 
 
 
X
 
 
Ratings Agency Updates
 
 
 
X
 
X
Prepayment Schedule and
 
 
 
 
 
 
 
History
 
 
 
 
 
X
Yield Adjustments
 
X
 
 
 
 
 
 
209

 
Fair Value Measurements of Long-term Debt

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of June 30, 2011 and December 31, 2010 are summarized in the following table:

 
 
June 30, 2011
 
December 31, 2010
Company
 
Book Value
 
Fair Value
 
Book Value
 
Fair Value
 
 
(in thousands)
APCo
 
$
 3,725,886 
 
$
 4,075,642 
 
$
 3,561,141 
 
$
 3,878,557 
CSPCo
 
 
 1,438,969 
 
 
 1,581,261 
 
 
 1,438,830 
 
 
 1,571,219 
I&M
 
 
 1,965,094 
 
 
 2,141,768 
 
 
 2,004,226 
 
 
 2,169,520 
OPCo
 
 
 2,614,781 
 
 
 2,855,349 
 
 
 2,729,522 
 
 
 2,945,280 
PSO
 
 
 945,650 
 
 
 1,035,124 
 
 
 971,186 
 
 
 1,040,656 
SWEPCo
 
 
 1,769,646 
 
 
 1,941,357 
 
 
 1,769,520 
 
 
 1,931,516 

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

·  
Acceptable investments (rated investment grade or above when purchased).
·  
Maximum percentage invested in a specific type of investment.
·  
Prohibition of investment in obligations of AEP or its affiliates.
·  
Withdrawals permitted only for payment of decommissioning costs and trust expenses.

I&M maintains trust records for each regulatory jurisdiction.  These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities.  The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value.  I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose.  Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the equity and debt investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.  The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities.  Regulatory approval is required to withdraw decommissioning funds.
 
210

 
 
The following is a summary of nuclear trust fund investments at June 30, 2011 and December 31, 2010:

 
 
 
June 30, 2011
 
December 31, 2010
 
 
 
Estimated
 
Gross
 
Other-Than-
 
Estimated
 
Gross
 
Other-Than-
 
 
Fair
Unrealized
Temporary
Fair
Unrealized
Temporary
 
 
Value
Gains
Impairments
Value
Gains
Impairments
 
 
 
(in thousands)
Cash and Cash Equivalents
 
$
 17,114 
 
$
 - 
 
$
 - 
 
$
 20,039 
 
$
 - 
 
$
 - 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 
 483,677 
 
 
 27,160 
 
 
 (1,269)
 
 
 461,084 
 
 
 22,582 
 
 
 (1,489)
 
Corporate Debt
 
 
 56,617 
 
 
 3,495 
 
 
 (785)
 
 
 59,463 
 
 
 3,716 
 
 
 (1,905)
 
State and Local Government
 
 
 338,145 
 
 
 1,031 
 
 
 (1,169)
 
 
 340,786 
 
 
 (975)
 
 
 (340)
 
  Subtotal Fixed Income Securities
 
 878,439 
 
 
 31,686 
 
 
 (3,223)
 
 
 861,333 
 
 
 25,323 
 
 
 (3,734)
Equity Securities - Domestic
 
 
 678,589 
 
 
 231,186 
 
 
 (104,828)
 
 
 633,855 
 
 
 183,447 
 
 
 (122,889)
Spent Nuclear Fuel and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning Trusts
 
$
 1,574,142 
 
$
 262,872 
 
$
 (108,051)
 
$
 1,515,227 
 
$
 208,770 
 
$
 (126,623)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2011 and 2010:

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
(in thousands)
Proceeds from Investment Sales
$
 176,927 
 
$
 360,185 
 
$
 464,688 
 
$
 592,263 
Purchases of Investments
 
 186,217 
 
 
 369,427 
 
 
 492,162 
 
 
 617,059 
Gross Realized Gains on Investment Sales
 
 7,392 
 
 
 1,022 
 
 
 12,405 
 
 
 6,350 
Gross Realized Losses on Investment Sales
 
 4,043 
 
 
 236 
 
 
 9,290 
 
 
 417 

The adjusted cost of debt securities was $848 million and $835 million as of June 30, 2011 and December 31, 2010, respectively.  The adjusted cost of equity securities was $447 million and $451 million as of June 30, 2011 and December 31, 2010, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at June 30, 2011 was as follows:

 
Fair Value
 
 
of Debt
 
 
Securities
 
 
(in thousands)
 
Within 1 year
 $ 77,143  
1 year – 5 years
    256,056  
5 years – 10 years
    281,130  
After 10 years
  264,110  
Total
 $ 878,439  
 
 
211

 
Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2011 and December 31, 2010.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in management’s valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2011
APCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 935 
 
$
 230,136 
 
$
 16,634 
 
$
 (188,100)
 
$
 59,605 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 4,289 
 
 
 - 
 
 
 (2,596)
 
 
 1,693 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,662 
 
 
 2,662 
Total Risk Management Assets
$
 935 
 
$
 234,425 
 
$
 16,634 
 
$
 (188,034)
 
$
 63,960 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 901 
 
$
 211,634 
 
$
 11,263 
 
$
 (195,489)
 
$
 28,309 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 3,067 
 
 
 50 
 
 
 (2,596)
 
 
 521 
Total Risk Management Liabilities
$
 901 
 
$
 214,701 
 
$
 11,313 
 
$
 (198,085)
 
$
 28,830 

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2010
APCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 1,686 
 
$
 330,605 
 
$
 13,791 
 
$
 (270,012)
 
$
 76,070 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,591 
 
 
 - 
 
 
 (2,258)
 
 
 333 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 11,888 
 
 
 - 
 
 
 - 
 
 
 11,888 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 3,371 
 
 
 3,371 
Total Risk Management Assets
$
 1,686 
 
$
 345,084 
 
$
 13,791 
 
$
 (268,899)
 
$
 91,662 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 1,653 
 
$
 312,258 
 
$
 8,660 
 
$
 (284,432)
 
$
 38,139 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,985 
 
 
 - 
 
 
 (2,258)
 
 
 727 
Total Risk Management Liabilities
$
 1,653 
 
$
 315,243 
 
$
 8,660 
 
$
 (286,690)
 
$
 38,866 


 
212

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2011
CSPCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 542 
 
$
 132,069 
 
$
 9,623 
 
$
 (107,783)
 
$
 34,451 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,438 
 
 
 - 
 
 
 (1,500)
 
 
 938 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,540 
 
 
 1,540 
Total Risk Management Assets
$
 542 
 
$
 134,507 
 
$
 9,623 
 
$
 (107,743)
 
$
 36,929 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 521 
 
$
 121,351 
 
$
 6,517 
 
$
 (112,054)
 
$
 16,335 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,768 
 
 
 29 
 
 
 (1,500)
 
 
 297 
Total Risk Management Liabilities
$
 521 
 
$
 123,119 
 
$
 6,546 
 
$
 (113,554)
 
$
 16,632 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2010
CSPCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 972 
 
$
 185,699 
 
$
 7,950 
 
$
 (150,930)
 
$
 43,691 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,531 
 
 
 - 
 
 
 (1,302)
 
 
 229 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,943 
 
 
 1,943 
Total Risk Management Assets
$
 972 
 
$
 187,230 
 
$
 7,950 
 
$
 (150,289)
 
$
 45,863 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 953 
 
$
 175,078 
 
$
 4,975 
 
$
 (159,235)
 
$
 21,771 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,721 
 
 
 - 
 
 
 (1,302)
 
 
 419 
Total Risk Management Liabilities
$
 953 
 
$
 176,799 
 
$
 4,975 
 
$
 (160,537)
 
$
 22,190 

 
213

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2011
I&M
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 555 
 
$
 143,023 
 
$
 9,864 
 
$
 (108,585)
 
$
 44,857 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,512 
 
 
 - 
 
 
 (1,538)
 
 
 974 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,579 
 
 
 1,579 
Total Risk Management Assets
 
 555 
 
 
 145,535 
 
 
 9,864 
 
 
 (108,544)
 
 
 47,410 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (d)
 
 - 
 
 
 4,699 
 
 
 - 
 
 
 12,415 
 
 
 17,114 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 - 
 
 
 483,677 
 
 
 - 
 
 
 - 
 
 
 483,677 
 
Corporate Debt
 
 - 
 
 
 56,617 
 
 
 - 
 
 
 - 
 
 
 56,617 
 
State and Local Government
 
 - 
 
 
 338,145 
 
 
 - 
 
 
 - 
 
 
 338,145 
 
 
Subtotal Fixed Income Securities
 
 - 
 
 
 878,439 
 
 
 - 
 
 
 - 
 
 
 878,439 
Equity Securities - Domestic (e)
 
 678,589 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 678,589 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 678,589 
 
 
 883,138 
 
 
 - 
 
 
 12,415 
 
 
 1,574,142 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 679,144 
 
$
 1,028,673 
 
$
 9,864 
 
$
 (96,129)
 
$
 1,621,552 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 534 
 
$
 122,403 
 
$
 6,684 
 
$
 (112,959)
 
$
 16,662 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,815 
 
 
 30 
 
 
 (1,538)
 
 
 307 
Total Risk Management Liabilities
$
 534 
 
$
 124,218 
 
$
 6,714 
 
$
 (114,497)
 
$
 16,969 

 
214

 

 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
 
December 31, 2010
I&M
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 1,014 
 
$
 209,031 
 
$
 8,295 
 
$
 (161,531)
 
$
 56,809 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,533 
 
 
 - 
 
 
 (1,358)
 
 
 175 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,027 
 
 
 2,027 
Total Risk Management Assets
 
 1,014 
 
 
 210,564 
 
 
 8,295 
 
 
 (160,862)
 
 
 59,011 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (d)
 
 - 
 
 
 7,898 
 
 
 - 
 
 
 12,141 
 
 
 20,039 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 - 
 
 
 461,084 
 
 
 - 
 
 
 - 
 
 
 461,084 
 
Corporate Debt
 
 - 
 
 
 59,463 
 
 
 - 
 
 
 - 
 
 
 59,463 
 
State and Local Government
 
 - 
 
 
 340,786 
 
 
 - 
 
 
 - 
 
 
 340,786 
 
 
Subtotal Fixed Income Securities
 
 - 
 
 
 861,333 
 
 
 - 
 
 
 - 
 
 
 861,333 
Equity Securities - Domestic (e)
 
 633,855 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 633,855 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 633,855 
 
 
 869,231 
 
 
 - 
 
 
 12,141 
 
 
 1,515,227 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 634,869 
 
$
 1,079,795 
 
$
 8,295 
 
$
 (148,721)
 
$
 1,574,238 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 994 
 
$
 186,898 
 
$
 5,187 
 
$
 (170,201)
 
$
 22,878 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,795 
 
 
 - 
 
 
 (1,358)
 
 
 437 
Total Risk Management Liabilities
$
 994 
 
$
 188,693 
 
$
 5,187 
 
$
 (171,559)
 
$
 23,315 
 
 
215

 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
June 30, 2011
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Cash Deposits (c)
$
 26 
 
$
 - 
 
$
 - 
 
$
 22 
 
$
 48 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
 
 649 
 
 
 193,046 
 
 
 11,535 
 
 
 (162,774)
 
 
 42,456 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,993 
 
 
 - 
 
 
 (1,801)
 
 
 1,192 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,847 
 
 
 1,847 
Total Risk Management Assets
 
 649 
 
 
 196,039 
 
 
 11,535 
 
 
 (162,728)
 
 
 45,495 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 675 
 
$
 196,039 
 
$
 11,535 
 
$
 (162,706)
 
$
 45,543 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 625 
 
$
 180,588 
 
$
 7,818 
 
$
 (167,994)
 
$
 21,037 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,128 
 
 
 35 
 
 
 (1,801)
 
 
 362 
Total Risk Management Liabilities
$
 625 
 
$
 182,716 
 
$
 7,853 
 
$
 (169,795)
 
$
 21,399 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2010
OPCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Cash Deposits (c)
$
 26 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 26 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
 
 1,186 
 
 
 314,560 
 
 
 9,709 
 
 
 (269,216)
 
 
 56,239 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,764 
 
 
 - 
 
 
 (1,590)
 
 
 174 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,372 
 
 
 2,372 
Total Risk Management Assets
 
 1,186 
 
 
 316,324 
 
 
 9,709 
 
 
 (268,434)
 
 
 58,785 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 1,212 
 
$
 316,324 
 
$
 9,709 
 
$
 (268,434)
 
$
 58,811 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 1,163 
 
$
 302,299 
 
$
 6,101 
 
$
 (279,505)
 
$
 30,058 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,101 
 
 
 - 
 
 
 (1,590)
 
 
 511 
Total Risk Management Liabilities
$
 1,163 
 
$
 304,400 
 
$
 6,101 
 
$
 (281,095)
 
$
 30,569 

 
216

 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
June 30, 2011
PSO
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 2 
 
$
 14,471 
 
$
 - 
 
$
 (13,493)
 
$
 980 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 202 
 
 
 - 
 
 
 (7)
 
 
 195 
Total Risk Management Assets
$
 2 
 
$
 14,673 
 
$
 - 
 
$
 (13,500)
 
$
 1,175 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 1 
 
$
 14,559 
 
$
 - 
 
$
 (13,537)
 
$
 1,023 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 19 
 
 
 - 
 
 
 (7)
 
 
 12 
Total Risk Management Liabilities
$
 1 
 
$
 14,578 
 
$
 - 
 
$
 (13,544)
 
$
 1,035 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2010
PSO
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 - 
 
$
 21,119 
 
$
 1 
 
$
 (20,335)
 
$
 785 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges
 
 - 
 
 
 134 
 
 
 - 
 
 
 - 
 
 
 134 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 13,558 
 
 
 - 
 
 
 - 
 
 
 13,558 
Total Risk Management Assets
$
 - 
 
$
 34,811 
 
$
 1 
 
$
 (20,335)
 
$
 14,477 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 - 
 
$
 21,498 
 
$
 - 
 
$
 (20,379)
 
$
 1,119 


 
217

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2011
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 2 
 
$
 13,840 
 
$
 - 
 
$
 (13,341)
 
$
 501 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 186 
 
 
 - 
 
 
 (5)
 
 
 181 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 1,227 
 
 
 - 
 
 
 - 
 
 
 1,227 
Total Risk Management Assets
$
 2 
 
$
 15,253 
 
$
 - 
 
$
 (13,346)
 
$
 1,909 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 1 
 
$
 14,906 
 
$
 - 
 
$
 (13,384)
 
$
 1,523 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 16 
 
 
 - 
 
 
 (5)
 
 
 11 
Total Risk Management Liabilities
$
 1 
 
$
 14,922 
 
$
 - 
 
$
 (13,389)
 
$
 1,534 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2010
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 - 
 
$
 36,632 
 
$
 2 
 
$
 (35,115)
 
$
 1,519 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges
 
 - 
 
 
 123 
 
 
 - 
 
 
 - 
 
 
 123 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 5 
 
 
 - 
 
 
 - 
 
 
 5 
Total Risk Management Assets
$
 - 
 
$
 36,760 
 
$
 2 
 
$
 (35,115)
 
$
 1,647 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (f)
$
 - 
 
$
 39,592 
 
$
 - 
 
$
 (35,187)
 
$
 4,405 

(a)
Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
(b)
Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.”  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This MTM value will be amortized into revenues over the remaining life of the contracts.
(c)
Level 1 amounts primarily represent investments in money market funds.
(d)
Amounts in “Other” column primarily represent accrued interest receivables from financial institutions.  Level 2 amounts primarily represent investments in money market funds.
(e)
Amounts represent publicly traded equity securities and equity-based mutual funds.
(f)
Substantially comprised of power contracts for APCo, CSPCo, I&M and OPCo and coal contracts for PSO and SWEPCo.

There were no transfers between Level 1 and Level 2 during the six months ended June 30, 2011 and 2010.
 
218

 

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:

Three Months Ended June 30, 2011
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of March 31, 2011
 
$
 5,472 
 
$
 3,134 
 
$
 3,209 
 
$
 3,759 
 
$
 - 
 
$
 - 
Realized Gain (Loss) Included in Net Income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(or Changes in Net Assets) (a) (b)
 
 
 (3,219)
 
 
 (1,863)
 
 
 (1,910)
 
 
 (2,233)
 
 
 - 
 
 
 - 
Unrealized Gain (Loss) Included in Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (or Changes in Net Assets) Relating
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
to Assets Still Held at the Reporting Date (a)
 
 
 - 
 
 
 527 
 
 
 - 
 
 
 622 
 
 
 - 
 
 
 - 
Realized and Unrealized Gains (Losses)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Included in Other Comprehensive Income
 
 
 (50)
 
 
 (29)
 
 
 (30)
 
 
 (35)
 
 
 - 
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 4,814 
 
 
 2,786 
 
 
 2,856 
 
 
 3,340 
 
 
 - 
 
 
 - 
Transfers into Level 3 (d) (f)
 
 
 1,125 
 
 
 644 
 
 
 661 
 
 
 773 
 
 
 - 
 
 
 - 
Transfers out of Level 3 (e) (f)
 
 
 (213)
 
 
 (122)
 
 
 (125)
 
 
 (147)
 
 
 - 
 
 
 - 
Changes in Fair Value Allocated to Regulated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jurisdictions (g)
 
 
 (2,608)
 
 
 (2,000)
 
 
 (1,511)
 
 
 (2,397)
 
 
 - 
 
 
 - 
Balance as of June 30, 2011
 
$
 5,321 
 
$
 3,077 
 
$
 3,150 
 
$
 3,682 
 
$
 - 
 
$
 - 

Three Months Ended June 30, 2010
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of March 31, 2010
 
$
 18,687 
 
$
 10,570 
 
$
 10,662 
 
$
 12,180 
 
$
 2 
 
$
 4 
Realized Gain (Loss) Included in Net Income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(or Changes in Net Assets) (a) (b)
 
 
 (8,409)
 
 
 (4,753)
 
 
 (4,794)
 
 
 (5,471)
 
 
 (1)
 
 
 (1)
Unrealized Gain (Loss) Included in Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (or Changes in Net Assets) Relating
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
to Assets Still Held at the Reporting Date (a)
 
 
 - 
 
 
 (556)
 
 
 - 
 
 
 (667)
 
 
 - 
 
 
 - 
Realized and Unrealized Gains (Losses)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Included in Other Comprehensive Income
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 4,845 
 
 
 2,741 
 
 
 2,764 
 
 
 3,154 
 
 
 (4)
 
 
 (5)
Transfers into Level 3 (d) (f)
 
 
 1,332 
 
 
 753 
 
 
 760 
 
 
 867 
 
 
 - 
 
 
 - 
Transfers out of Level 3 (e) (f)
 
 
 (2,006)
 
 
 (1,135)
 
 
 (1,145)
 
 
 (1,306)
 
 
 - 
 
 
 - 
Changes in Fair Value Allocated to Regulated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jurisdictions (g)
 
 
 (3,575)
 
 
 (1,467)
 
 
 (2,038)
 
 
 (1,688)
 
 
 1 
 
 
 - 
Balance as of June 30, 2010
 
$
 10,874 
 
$
 6,153 
 
$
 6,209 
 
$
 7,069 
 
$
 (2)
 
$
 (2)

Six Months Ended June 30, 2011
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of December 31, 2010
 
$
 5,131 
 
$
 2,975 
 
$
 3,108 
 
$
 3,608 
 
$
 1 
 
$
 2 
Realized Gain (Loss) Included in Net Income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(or Changes in Net Assets) (a) (b)
 
 
 (2,489)
 
 
 (1,436)
 
 
 (1,473)
 
 
 (1,722)
 
 
 - 
 
 
 - 
Unrealized Gain (Loss) Included in Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (or Changes in Net Assets) Relating
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
to Assets Still Held at the Reporting Date (a)
 
 
 - 
 
 
 2,258 
 
 
 - 
 
 
 2,691 
 
 
 - 
 
 
 - 
Realized and Unrealized Gains (Losses)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Included in Other Comprehensive Income
 
 
 (50)
 
 
 (29)
 
 
 (30)
 
 
 (35)
 
 
 - 
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 3,881 
 
 
 2,254 
 
 
 2,311 
 
 
 2,701 
 
 
 - 
 
 
 - 
Transfers into Level 3 (d) (f)
 
 
 1,221 
 
 
 699 
 
 
 718 
 
 
 840 
 
 
 - 
 
 
 - 
Transfers out of Level 3 (e) (f)
 
 
 (2,853)
 
 
 (1,644)
 
 
 (1,713)
 
 
 (2,004)
 
 
 - 
 
 
 - 
Changes in Fair Value Allocated to Regulated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jurisdictions (g)
 
 
 480 
 
 
 (2,000)
 
 
 229 
 
 
 (2,397)
 
 
 (1)
 
 
 (2)
Balance as of June 30, 2011
 
$
 5,321 
 
$
 3,077 
 
$
 3,150 
 
$
 3,682 
 
$
 - 
 
$
 - 
 
 
219

 
Six Months Ended June 30, 2010
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of December 31, 2009
 
$
 9,428 
 
$
 4,776 
 
$
 4,816 
 
$
 5,569 
 
$
 2 
 
$
 3 
Realized Gain (Loss) Included in Net Income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(or Changes in Net Assets) (a) (b)
 
 
 1,232 
 
 
 693 
 
 
 698 
 
 
 797 
 
 
 7 
 
 
 9 
Unrealized Gain (Loss) Included in Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (or Changes in Net Assets) Relating
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
to Assets Still Held at the Reporting Date (a)
 
 
 - 
 
 
 5,157 
 
 
 - 
 
 
 5,849 
 
 
 - 
 
 
 - 
Realized and Unrealized Gains (Losses)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Included in Other Comprehensive Income
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 (4,173)
 
 
 (2,321)
 
 
 (2,341)
 
 
 (2,675)
 
 
 (6)
 
 
 (7)
Transfers into Level 3 (d) (f)
 
 
 603 
 
 
 315 
 
 
 318 
 
 
 366 
 
 
 - 
 
 
 - 
Transfers out of Level 3 (e) (f)
 
 
 (1,738)
 
 
 (999)
 
 
 (1,008)
 
 
 (1,148)
 
 
 - 
 
 
 - 
Changes in Fair Value Allocated to Regulated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jurisdictions (g)
 
 
 5,522 
 
 
 (1,468)
 
 
 3,726 
 
 
 (1,689)
 
 
 (5)
 
 
 (7)
Balance as of June 30, 2010
 
$
 10,874 
 
$
 6,153 
 
$
 6,209 
 
$
 7,069 
 
$
 (2)
 
$
 (2)

(a)
Included in revenues on the Condensed Statements of Income.
(b)
Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)
Represents the settlement of risk management commodity contracts for the reporting period.
(d)
Represents existing assets or liabilities that were previously categorized as Level 2.
(e)
Represents existing assets or liabilities that were previously categorized as Level 3.
(f)
Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(g)
Relates to the net gains (losses) of those contracts that are not reflected on the Condensed Statements of Income.  These net gains (losses) are recorded as regulatory assets/liabilities.

10.  INCOME TAXES

The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System.  The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense.  The tax benefit of the Parent is allocated to its subsidiaries with taxable income.  With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2001.  The Registrant Subsidiaries have completed the exam for the years 2001 through 2006 and have issues that are being pursued at the appeals level.  In April 2011, the IRS’s examination of the years 2007 and 2008 was concluded with a settlement of all outstanding issues.  The settlement will not have a material impact on net income, cash flows or financial condition.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions.  Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on net income.

The Registrant Subsidiaries file income tax returns in various state and local jurisdictions.  These taxing authorities routinely examine their tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions.  Management believes that previously filed tax returns have positions that may be challenged by these tax authorities.  However, management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income.  With few exceptions, the Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2000.
 
220

 
 
Federal Tax 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 by the Registrant Subsidiaries in March 2010.  This reduction did not materially affect the Registrant Subsidiaries' cash flows or financial condition.  For the six months ended June 30, 2010, the Registrant Subsidiaries reflected a decrease in deferred tax assets, which was partially offset by recording net tax regulatory assets in jurisdictions with regulated operations, resulting in a decrease in net income as follows:

 
 
Net Reduction
 
Tax
 
 
 
 
to Deferred
 
Regulatory
 
Decrease in
Company
 
Tax Assets
 
Assets, Net
 
Net Income
 
 
(in thousands)
APCo
 
$
 9,397 
 
$
8,831 
 
$
 566 
CSPCo
 
 
 4,386 
 
 
2,970 
 
 
 1,416 
I&M
 
 
 7,212 
 
 
6,528 
 
 
 684 
OPCo
 
 
 8,385 
 
 
4,020 
 
 
 4,365 
PSO
 
 
 3,172 
 
 
3,172 
 
 
 - 
SWEPCo
 
 
 3,412 
 
 
3,412 
 
 
 - 

The Small Business Jobs Act (the Act) was enacted in September 2010.  Included in the Act was a one-year extension of the 50% bonus depreciation provision.  The Tax Relief, Unemployment Insurance Reauthorization and the Job Creation Act of 2010 extended the life of research and development, employment and several energy tax credits originally scheduled to expire at the end of 2010.  In addition, the Act extended the time for claiming bonus depreciation and increased the deduction to 100% for part of 2010 and 2011.  The enacted provisions will not have a material impact on the Registrant Subsidiaries’ net income or financial condition.

State Tax Legislation

Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rates from 8.5% to 6.5%.  The current 8.5% Indiana corporate income tax rate is scheduled for a 0.5% reduction each year beginning after June 30, 2012 with the final reduction occurring in years beginning after June 30, 2015.  In addition, Michigan repealed its Business Tax regime in May 2011 and replaced it with a traditional corporate net income tax with a rate of 6%.  The enacted provisions will not have a material impact on the Registrant Subsidiaries’ net income, cash flows or financial condition.
 
221

 
 
11.  FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first six months of 2011 are shown in the tables below:

 
 
 
 
Principal
 
Interest
 
Due
Company
 
Type of Debt
 
Amount
 
Rate
 
Date
Issuances:
 
 
 
(in thousands)
 
(%)
 
 
APCo
 
Senior Unsecured Notes
 
$
 350,000 
 
4.60 
 
2021 
APCo
 
Pollution Control Bonds
 
 
 65,350 
 
2.00 
 
2012 
APCo
 
Pollution Control Bonds
 
 
 75,000 
(a)
Variable
 
2036 
APCo
 
Pollution Control Bonds
 
 
 54,375 
(a)
Variable
 
2042 
APCo
 
Pollution Control Bonds
 
 
 50,275 
(a)
Variable
 
2036 
APCo
 
Pollution Control Bonds
 
 
 50,000 
(a)
Variable
 
2042 
I&M
 
Pollution Control Bonds
 
 
 52,000 
(a)
Variable
 
2021 
I&M
 
Pollution Control Bonds
 
 
 25,000 
(a)
Variable
 
2019 
OPCo
 
Pollution Control Bonds
 
 
 50,000 
(a)
Variable
 
2014 
PSO
 
Senior Unsecured Notes
 
 
 250,000 
 
4.40 
 
2021 
PSO
 
Notes Payable
 
 
 1,187 
 
3.00 
 
2026 

(a)  
These pollution control bonds are subject to redemption earlier than the maturity date.  Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year – Nonaffiliated on the balance sheets.

 
 
 
 
 
Principal
 
Interest
 
Due
Company
 
Type of Debt
 
Amount Paid
 
Rate
 
Date
Retirements and
 
 
 
(in thousands)
 
(%)
 
 
 
Principal Payments:
 
 
 
 
 
 
 
 
 
APCo
 
Pollution Control Bonds
 
$
 75,000 
 
Variable
 
2036 
APCo
 
Pollution Control Bonds
 
 
 54,375 
 
Variable
 
2042 
APCo
 
Pollution Control Bonds
 
 
 50,000 
 
Variable
 
2042 
APCo
 
Pollution Control Bonds
 
 
 50,275 
 
Variable
 
2036 
APCo
 
Senior Unsecured Notes
 
 
 250,000 
 
5.55 
 
2011 
APCo
 
Land Note
 
 
 11 
 
13.718 
 
2026 
I&M
 
Pollution Control Bonds
 
 
 52,000 
 
Variable
 
2021 
I&M
 
Pollution Control Bonds
 
 
 25,000 
 
Variable
 
2019 
I&M
 
Notes Payable
 
 
 10,894 
 
Variable
 
2015 
I&M
 
Notes Payable
 
 
 13,150 
 
5.16 
 
2014 
I&M
 
Notes Payable
 
 
 15,482 
 
5.44 
 
2013 
OPCo
 
Pollution Control Bonds
 
 
 65,000 
 
Variable
 
2036 
OPCo
 
Pollution Control Bonds
 
 
 50,000 
 
Variable
 
2014 
OPCo
 
Pollution Control Bonds
 
 
 50,000 
 
Variable
 
2014 
PSO
 
Senior Unsecured Notes
 
 
 200,000 
 
6.00 
 
2032 
PSO
 
Senior Unsecured Notes
 
 
 75,000 
 
4.70 
 
2011 

In July 2011, SWEPCo retired $41 million of 4.5% Pollution Control Bonds due in 2011.

In July 2011, I&M retired $2 million of Notes Payable related to DCC Fuel.

As of June 30, 2011, trustees held, on behalf of OPCo, $418 million of its reacquired Pollution Control Bonds.
 
222

 

Dividend Restrictions

The Registrant Subsidiaries pay dividends to Parent provided funds are legally available.  Various charter provisions and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

Federal Power Act

The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.”  The term “capital account” is not defined in the Federal Power Act or its regulations.  As applicable, the Registrant Subsidiaries understand “capital account” to mean the par value of the common stock multiplied by the number of shares outstanding.

Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants.  Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo.

None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

Charter and Leverage Restrictions

Provisions within the articles or certificates of incorporation of the Registrant Subsidiaries relating to preferred stock or shares restrict the payment of cash dividends on common and preferred stock or shares.

Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries.  The AEP System Utility Money Pool operates in accordance with the terms and conditions approved in a regulatory order.  The amount of outstanding loans (borrowings) to/from the Utility Money Pool as of June 30, 2011 and December 31, 2010 is included in Advances to/from Affiliates on each of the Registrant Subsidiaries’ balance sheets.  The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the six months ended June 30, 2011 are described in the following table:

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loans
 
 
 
 
 
Maximum
 
Maximum
 
Average
 
Average
 
(Borrowings)
 
Authorized
 
 
Borrowings
 
Loans
 
Borrowings
 
Loans
 
to/from Utility
 
Short-term
 
 
from Utility
 
to Utility
 
from Utility
 
to Utility
 
Money Pool as of
 
Borrowing
Company
 
Money Pool
 
Money Pool
 
Money Pool
 
Money Pool
 
June 30, 2011
 
Limit
 
 
(in thousands)
APCo
 
$
 195,945 
 
$
 393,811 
 
$
 102,608 
 
$
 154,349 
 
$
 162,787 
 
$
 600,000 
CSPCo
 
 
 17,256 
 
 
 130,250 
 
 
 10,098 
 
 
 78,172 
 
 
 71,323 
 
 
 350,000 
I&M
 
 
 52,098 
 
 
 89,276 
 
 
 22,098 
 
 
 32,773 
 
 
 (24,537)
 
 
 500,000 
OPCo
 
 
 51,169 
 
 
 237,196 
 
 
 17,873 
 
 
 116,937 
 
 
 136,965 
 
 
 600,000 
PSO
 
 
 96,034 
 
 
 255,611 
 
 
 45,042 
 
 
 95,323 
 
 
 110 
 
 
 300,000 
SWEPCo
 
 
 26,424 
 
 
 105,184 
 
 
 11,178 
 
 
 38,798 
 
 
 34,684 
 
 
 350,000 

 
223

 
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:

 
 
Six Months Ended June 30,
 
 
2011
 
2010
Maximum Interest Rate
    0.56 %     0.51 %
Minimum Interest Rate
    0.06 %     0.09 %

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the six months ended June 30, 2011 and 2010 are summarized for all Registrant Subsidiaries in the following table:

 
 
Average Interest Rate
 
Average Interest Rate
 
 
for Funds Borrowed
 
for Funds Loaned
 
 
from Utility Money Pool for
 
to Utility Money Pool for
 
 
Six Months Ended June 30,
 
Six Months Ended June 30,
Company
 
2011
 
2010
 
2011
 
2010
 
 
 
   
 
   
 
   
 
 
APCo
    0.38 %     0.23 %     0.27 %     - %
CSPCo
    0.52 %     0.18 %     0.27 %     0.26 %
I&M
    0.44 %     - %     0.23 %     0.21 %
OPCo
    0.41 %     - %     0.24 %     0.18 %
PSO
    0.41 %     0.28 %     0.19 %     0.16 %
SWEPCo
    0.25 %     0.19 %     0.33 %     0.25 %

Short-term Debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The Registrant Subsidiaries’ outstanding short-term debt was as follows:
 
 
 
 
 
 
June 30, 2011
 
December 31, 2010
 
 
 
 
 
Outstanding
 
Interest
 
Outstanding
 
Interest
Company
 
Type of Debt
Amount
Rate (b)
 
Amount
Rate (b)
 
 
 
 
 
(in thousands)
 
 
 
 
(in thousands)
 
 
 
SWEPCo
 
Line of Credit – Sabine (a)
 
$
 - 
 
 - 
%
 
$
 6,217 
 
 2.15 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Sabine Mining Company is a consolidated variable interest entity.
(b)
Weighted average rate.

 
224

 
Credit Facilities

AEP has two $1.5 billion credit facilities, under which up to $1.35 billion may be issued as letters of credit.  In July 2011, AEP replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015.  As of June 30, 2011, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $150 thousand for I&M and $4 million for SWEPCo.

In March 2011, the Registrant Subsidiaries and certain other companies in the AEP System terminated a $478 million credit agreement that was scheduled to mature in April 2011 and was used to support variable rate Pollution Control Bonds.  In March 2011, certain variable rate Pollution Control Bonds were remarketed and supported by bilateral letters of credit for $361 million while others were reacquired and are being held in trust.  As of June 30, 2011, $472 million of variable rate Pollution Control Bonds were remarketed or reacquired as follows:

 
 
June 30, 2011
 
 
 
 
 
Reacquired and
 
Bilateral Letters
Company
 
Remarketed
 
Held in Trust
 
of Credit Issued
 
 
(in thousands)
APCo
 
$
229,650 
 
$
 - 
 
$
 232,293 
I&M
 
 
77,000 
 
 
 - 
 
 
 77,886 
OPCo
 
 
50,000 
 
 
115,000 
 
 
 50,575 

Sale of Receivables – AEP Credit

Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables.  APCo does not have regulatory authority to sell its West Virginia accounts receivable.  The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ income statements.  The Registrant Subsidiaries manage and service their customer accounts receivable sold.

In July 2011, AEP Credit renewed its receivables securitization agreement.  The agreement provides commitments of $750 million from bank conduits to finance receivables from AEP Credit with an increase to $800 million for the months of July, August and September to accommodate seasonal demand.  A commitment of $375 million, with the seasonal increase to $425 million for the months of July, August and September, expires in June 2012 and the remaining commitment of $375 million expires in June 2014.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of June 30, 2011 and December 31, 2010 was as follows:

 
 
 
June 30,
 
December 31,
Company
 
2011 
 
2010 
 
 
 
(in thousands)
APCo
 
$
 123,959 
 
$
 145,515 
CSPCo
 
 
 179,639 
 
 
 175,997 
I&M
 
 
 132,772 
 
 
 123,366 
OPCo
 
 
 192,529 
 
 
 168,701 
PSO
 
 
 150,689 
 
 
 121,679 
SWEPCo
 
 
 174,496 
 
 
 135,092 

 
225

 
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:

 
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Company
 
2011 
 
2010 
 
2011 
 
2010 
 
 
 
(in thousands)
APCo
 
$
 2,239 
 
$
 1,895 
 
$
 4,814 
 
$
 3,776 
CSPCo
 
 
 2,594 
 
 
 2,782 
 
 
 4,926 
 
 
 5,690 
I&M
 
 
 1,508 
 
 
 1,657 
 
 
 3,135 
 
 
 3,444 
OPCo
 
 
 1,811 
 
 
 2,449 
 
 
 3,514 
 
 
 5,149 
PSO
 
 
 1,483 
 
 
 1,367 
 
 
 2,717 
 
 
 2,750 
SWEPCo
 
 
 1,303 
 
 
 1,462 
 
 
 2,403 
 
 
 3,133 

The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:

 
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Company
 
2011 
 
2010 
 
2011 
 
2010 
 
 
 
(in thousands)
APCo
 
$
 284,715 
 
$
 317,120 
 
$
 650,924 
 
$
 758,830 
CSPCo
 
 
 374,925 
 
 
 422,628 
 
 
 781,571 
 
 
 847,313 
I&M
 
 
 315,551 
 
 
 297,384 
 
 
 666,572 
 
 
 636,593 
OPCo
 
 
 456,910 
 
 
 410,331 
 
 
 961,302 
 
 
 851,840 
PSO
 
 
 317,060 
 
 
 311,883 
 
 
 585,629 
 
 
 526,530 
SWEPCo
 
 
 375,903 
 
 
 338,286 
 
 
 690,027 
 
 
 657,245 
 
12.  COST REDUCTION INITIATIVES

In April 2010, management began initiatives to decrease both labor and non-labor expenses with a goal of achieving significant reductions in operation and maintenance expenses.  A total of 2,461 positions was eliminated across the AEP System as a result of process improvements, streamlined organizational designs and other efficiencies.  Most of the affected employees terminated employment May 31, 2010.  The severance program provided two weeks of base pay for every year of service along with other severance benefits.

Management recorded a charge to Other Operation expense during the second quarter of 2010 primarily related to severance benefits as the result of headcount reduction initiatives.  The total amount incurred in 2010 by Registrant Subsidiary was as follows:

Company
 
Total Cost Incurred
 
 
(in thousands)
APCo
 
$
 56,925 
CSPCo
 
 
 32,292 
I&M
 
 
 45,036 
OPCo
 
 
 53,108 
PSO
 
 
 24,005 
SWEPCo
 
 
 29,662 

The Registrant Subsidiaries’ cost reduction activity for the six months ended June 30, 2011 is described in the following table:

 
 
Balance at
 
 
 
 
 
 
 
 
Balance at
Company
 
December 31, 2010
 
Incurred
 
Settled
 
Adjustments
 
June 30, 2011
 
 
(in thousands)
APCo
 
$
 3,726 
 
$
 - 
 
$
 (2,327)
 
$
 (452)
 
$
 947 
CSPCo
 
 
 1,454 
 
 
 - 
 
 
 (1,346)
 
 
 (4)
 
 
 104 
I&M
 
 
 2,198 
 
 
 - 
 
 
 (1,650)
 
 
 (136)
 
 
 412 
OPCo
 
 
 2,919 
 
 
 - 
 
 
 (2,242)
 
 
 (128)
 
 
 549 
PSO
 
 
 1,526 
 
 
 - 
 
 
 (1,048)
 
 
 (167)
 
 
 311 
SWEPCo
 
 
 1,753 
 
 
 - 
 
 
 (1,325)
 
 
 (38)
 
 
 390 

The remaining accruals are included primarily in Other Current Liabilities on the Condensed Consolidated Balance Sheets.

 
226

 

COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the Registrant Subsidiaries’ management’s discussion and analysis.  The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (a) Management’s Discussion and Analysis, (b) financial statements, (c) footnotes and (d) the schedules of each individual registrant.  The Combined Management’s Discussion and Analysis of Registrant Subsidiaries section of the 2010 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

ENVIRONMENTAL ISSUES

The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements.  The Registrant Subsidiaries will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants from fossil fuel-fired power plants, new proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.

The Registrant Subsidiaries 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 I&M’s nuclear units.  Management is also involved in development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change.  See a complete discussion of these matters in the “Environmental Issues” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report.  Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  The Registrant Subsidiaries should be able to recover these expenditures through market prices in deregulated jurisdictions.  If not, the costs of environmental compliance could adversely affect future net income, cash flows and possibly financial condition.

Update to Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of June 30, 2011, the AEP System had a total generating capacity of nearly 38,000 MWs, of which 23,900 MWs are coal-fired.  In the second quarter of 2011, management refined the cost estimates of complying with these rules and other impacts of the environmental proposals on the coal-fired generating facilities.  For the Registrant Subsidiaries, management’s current ranges of estimates of environmental investments to comply with these proposed requirements, based upon the updates are listed below:

 
 
 
2012 to 2020
 
 
 
Estimated Environmental Investment
Company
 
Low
 
High
 
 
(in millions)
APCo
 
$
 580 
 
$
 765 
CSPCo
 
 
 552 
 
 
 736 
I&M
 
 
 660 
 
 
 885 
OPCo
 
 
 1,549 
 
 
 2,065 
PSO
 
 
 700 
 
 
 940 
SWEPCo
 
 
 900 
 
 
 1,200 

For APCo, the projected environmental investments above include both the conversion of 470 MWs of coal generation to 422 MWs of natural gas generation and the building of 580 MWs of natural gas-fired generation.  For OPCo, the investments above include the conversion of 600 MWs of coal generation to 510 MWs of natural gas-fired generation.
 
227

 

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules.  The cost estimates for each Registrant Subsidiary will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose standards more stringent than the proposed rules, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.

Subject to the factors listed above and based upon management’s current evaluation, the Registrant Subsidiaries may retire the following plants or units of plants before 2015:

 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs)
APCo
 
Clinch River Plant, Unit 3
 
 
 235 
APCo
 
Glen Lyn Plant
 
 
 335 
APCo
 
Kanawha River Plant
 
 
 400 
APCo/OPCo
 
Philip Sporn Plant
 
 
 1,050 
CSPCo
 
Conesville Plant, Unit 3
 
 
 165 
CSPCo
 
Picway Plant
 
 
 100 
I&M
 
Tanners Creek Plant, Units 1-3
 
 
 495 
OPCo
 
Kammer Plant
 
 
 630 
OPCo
 
Muskingum River Plant, Units 1-4
 
 
 840 
SWEPCo
 
Welsh Plant, Unit 2
 
 
 528 

Duke Energy Corporation, the operator of W. C. Beckjord Generating Station, has announced its intent to close the facility in 2015.  CSPCo owns 12.5% (54 MWs) of one unit at that station.

Management is also considering the conversion of some of the Registrant Subsidiaries’ coal units to natural gas, installing emission control equipment on other units and completing construction of the Turk and Dresden Plants.  Recovery of the remaining investments in facilities that may be closed will be subject to regulatory approval.

Cross State Air Pollution Rule (formerly the Clean Air Act Transport Rule)

In July 2010, the Federal EPA issued a proposed rule to replace the Clean Air Interstate Rule (CAIR) that would impose new and more stringent requirements to control SO2 and NOx emissions from fossil fuel-fired electric generating units in 31 states and the District of Columbia.  Each state covered by the proposed Clean Air Act Transport Rule (Transport Rule) was assigned an allowance budget for SO2 and/or NOx.  Limited interstate trading was allowed on a sub-regional basis and intrastate trading was allowed among generating units.  PSO’s and SWEPCo’s western states (Arkansas, Oklahoma and Texas) would be subject to only the seasonal NOx program, with new limits that were proposed to take effect in 2012.  The remainder of the states in which the AEP System operates would be subject to seasonal and annual NOx programs and an annual SO2 emissions reduction program that takes effect in two phases.  The first phase was effective in 2012 and more stringent SO2 emission reductions were proposed to take effect in 2014 in certain states.  The SO2 and NOx programs rely on newly-created allowances rather than relying on the CAIR NOx allowances or the Title IV Acid Rain Program allowances used in CAIR.

In July 2011, the Federal EPA released the final rule, renamed the Cross State Air Pollution Rule (CSAP Rule).  Like the proposed Transport Rule, the CSAP Rule relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states.  Interstate trading of allowances is allowed on a restricted sub-regional basis beginning in 2012.  Arkansas, Louisiana and Oklahoma are subject only to the seasonal NOx program in the final rule.  However, Texas is now subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program.  The annual SO2 allowance budgets in Indiana, Ohio and West Virginia have been reduced significantly in the final rule.
 
228

 
 
The time frames and stringency of the required emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and its electric utility customers.  The compliance plan described above was based on the requirements of the proposed Transport Rule.  The more stringent requirements included in the final CSAP Rule could accelerate unit retirements, increase capital requirements, constrain operations, decrease reliability and unfavorably impact financial condition if the increased costs are not recovered in rates or market prices.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

The Federal EPA issued the Clean Air Mercury Rule (CAMR) in 2005, setting mercury emission standards for new coal-fired power plants and requiring all states to issue new state implementation plans including mercury requirements for existing coal-fired power plants.  The CAMR was vacated by the D.C. Circuit Court of Appeals in 2008.  In response, the Federal EPA has been developing a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The Federal EPA Administrator signed a proposed HAPs rule in March 2011, but the rule has not yet been published in the Federal Register.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrochloric acid (as a surrogate for acid gases) for units burning coal and oil, on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  Compliance is required within three years of the effective date of the final rule, which is expected by November 2011 per the Federal EPA’s settlement agreement with several environmental groups.  A one-year extension may be available if the extension is necessary for the installation of controls.  Management is developing comments to submit to the Federal EPA and collecting additional information regarding the performance of the coal-fired units.  Comments will be accepted for 60 days after the rule is published in the Federal Register.

Management will urge the Federal EPA to carefully consider all of the options available so that costly and inefficient control requirements are not imposed regardless of unit size, age or other operating characteristics.  The AEP System has older coal units for which it may be economically inefficient to install scrubbers or other environmental controls.  Several of these units are included in the current list of potential plant closures discussed above.

Regional Haze – Oklahoma Affecting PSO

In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze state implementation plan (SIP) submitted by the State of Oklahoma through the Department of Environmental Quality.  The Federal EPA is proposing to approve all of the NOx control measures in the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO.  The Federal EPA is proposing a federal implementation plan (FIP) that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP.  The proposal is open for public comment.

Coal Combustion Residual Rule

In June 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at the coal-fired electric generating units.  The rule contains two alternative proposals, one that would impose federal hazardous waste disposal and management standards on these materials and one that would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management.  Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule.
 
229

 

Currently, approximately 40% of the coal ash and other residual products from the AEP System’s generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses.  Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes.  In addition,   surface impoundments and landfills to manage these materials are currently used at the generating facilities.  The Registrant Subsidiaries will incur significant costs to upgrade or close and replace their existing facilities.  Management estimates that the potential compliance costs associated with the proposed solid waste management alternative could be as high as $3.9 billion including AFUDC for units across the AEP System.  Regulation of these materials as hazardous wastes would significantly increase these costs.

Clean Water Act Regulations

In April 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling.  Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority.  Management is evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at the AEP System’s facilities.  Comments on the proposal were due in July 2011.

Global Warming

While comprehensive economy-wide regulation of CO2 emissions might be achieved through new legislation, Congress has yet to enact such legislation.  The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA.  The Federal EPA issued a final endangerment finding for CO2 emissions from new motor vehicles in December 2009 and final rules for new motor vehicles in May 2010.  The Federal EPA determined that CO2 emissions from stationary sources will be subject to regulation under the CAA and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, state implementation plan calls and federal implementation plans.  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 and announced a settlement agreement to issue proposed new source performance standards for utility boilers that would be applicable for both new and existing utility boilers.  It is not possible at this time to estimate the costs of compliance with these new standards, but they may be material.

The Registrant Subsidiaries’ fossil fuel-fired generating units are very large sources of CO2 emissions.  If substantial CO2 emission reductions are required, there will be significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units.  To the extent the Registrant Subsidiaries install additional controls on their generating plants to limit CO2 emissions and receive regulatory approvals to increase rates, cost recovery could have a positive effect on future earnings.  Prudently incurred capital investments made by the Registrant 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.  Management would expect these principles to apply to investments made to address new environmental requirements.  However, requests for rate increases reflecting these costs can affect the Registrant Subsidiaries adversely because the regulators could limit the amount or timing of increased costs that would be recoverable through higher rates.  In addition, to the extent the Registrant Subsidiaries’ costs are relatively higher than their competitors’ costs, such as operators of nuclear generation, it could reduce off-system sales or cause the Registrant Subsidiaries to lose customers in jurisdictions that permit customers to choose their supplier of generation service.
 
230

 

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 the Registrant Subsidiaries have generating facilities.  Certain states, including Ohio, Michigan, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements.  Management is 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.  The Registrant Subsidiaries have been named in pending lawsuits, which management is vigorously defending.  It is not possible to predict the outcome of these lawsuits or their impact on 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 the Registrant 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 net income, cash flows and financial condition.

For detailed information on global warming and the actions the AEP System is taking to address potential impacts, see Part I of the 2010 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters – Global Warming and “Combined Management Discussion and Analysis of Registrant Subsidiaries.”

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

Sources of Funding

Short-term funding for the Registrant Subsidiaries comes from AEP’s commercial paper program and revolving credit facilities through the Utility Money Pool.  AEP and its Registrant Subsidiaries operate a money pool to minimize the AEP System’s external short-term funding requirements and sell accounts receivable to provide liquidity.  Under credit facilities, $1.35 billion may be issued as letters of credit (LOC).  The Registrant Subsidiaries generally use short-term funding sources (the Utility Money Pool or receivables sales) to provide for interim financing of capital expenditures that exceed internally generated funds and periodically reduce their outstanding short-term debt through issuances of long-term debt, sale-leasebacks, leasing arrangements and additional capital contributions from Parent.

In March 2011, the Registrant Subsidiaries and certain other companies in the AEP System terminated a $478 million credit facility, used for letters of credit to support variable rate debt, that was scheduled to mature in April 2011.  In March 2011, APCo, I&M and OPCo issued bilateral letters of credit to support the remarketing of $230 million, $77 million and $50 million, respectively, of their variable rate debt.  OPCo reacquired $115 million which is held by a trustee on its behalf.

Dividend Restrictions

Under the Federal Power Act, the Registrant Subsidiaries are restricted from paying dividends out of stated capital.  Various charter provisions and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

Sales of Receivables

In July 2011, AEP Credit renewed its receivables securitization agreement.  The agreement provides a commitment of $750 million from bank conduits to purchase receivables with an increase to $800 million for the months of July, August and September to accommodate seasonal demand.  A commitment of $375 million with the seasonal increase to $425 million for the months of July, August and September expires in June 2012 and the remaining commitment of $375 million expires in June 2014.  AEP Credit purchases accounts receivable from the Registrant Subsidiaries.
 
231

 
 
MINE SAFETY INFORMATION

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations.  The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters.  SWEPCo, through its ownership of DHLC, CSPCo, through its ownership of Conesville Coal Preparation Company (CCPC), and OPCo, through its use of the Conner Run fly ash impoundment, are subject to the provisions of the Mine Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act.  DHLC, CCPC and Conner Run received the following notices of violation and proposed assessments under the Mine Act for the quarter ended June 30, 2011:

 
 
 
DHLC
 
CCPC
 
Conner Run
Number of Citations for Violations of Mandatory Health or
 
 
 
 
 
 
 
 
 
 
Safety Standards under 104 *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Orders Issued under 104(b) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Citations and Orders for Unwarrantable Failure
 
 
 
 
 
 
 
 
 
 
to Comply with Mandatory Health or Safety Standards under
 
 
 
 
 
 
 
 
 
 
104(d) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Flagrant Violations under 110(b)(2) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Imminent Danger Orders Issued under 107(a) *
 
 
 - 
 
 
 - 
 
 
 - 
Total Dollar Value of Proposed Assessments
 
$
 1,123 
 
$
 400 
 
$
 - 
Number of Mining-related Fatalities
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
 
 
 
 
 
 
 
* References to sections under the Mine Act
 
 
 
 
 
 
 
 
 

DHLC currently has three legal actions pending before the Federal Mine Safety and Health Review Commission. Two are related to actions challenging four violations issued by Mine Safety and Health Administration following an employee fatality in March 2009 and the third legal action is challenging a citation issued in August 2010 related to a dragline boom issue.

ACCOUNTING PRONOUNCEMENTS

Pronouncements Effective in the Future

The FASB issued ASU 2011-05 “Presentation of Comprehensive Income” eliminating the option to present the components of other comprehensive income as a part of the statement of shareholders’ equity.  The standard requires other comprehensive income be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income.  This standard will change the presentation of the financial statements but will not affect the calculation of net income or comprehensive income.  The Registrant Subsidiaries will retrospectively adopt ASU 2011-05 effective January 1, 2012.

Future Accounting Changes

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

 
232

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

The Registrant Subsidiaries’ risk management assets and liabilities are managed by AEPSC as agent.  The related risk management policies and procedures are instituted and administered by AEPSC.  See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Market Risk” section.  Also, see Note 8 – Derivatives and Hedging and Note 9 – Fair Value Measurements for additional information related to the Registrant Subsidiaries’ risk management contracts.

The following tables summarize the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2010:

 
MTM Risk Management Contract Net Assets (Liabilities)
 
 
Six Months Ended June 30, 2011
 
 
(in thousands)
 
 
 
 
 
 
APCo
 
 
 
 
 
 
 
 
Total MTM Risk Management Contract Net Assets at December 31, 2010
  $ 26,882  
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
    (3,767 )
Fair Value of New Contracts at Inception When Entered During the Period (a)
    -  
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
       
 During the Period     (13 )
Changes in Fair Value Due to Market Fluctuations During the Period (b)
    (861 )
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
    4,328  
Total MTM Risk Management Contract Net Assets at June 30, 2011
    26,569  
Commodity Cash Flow Hedge Contracts
    1,172  
Collateral Deposits
    7,389  
Total MTM Derivative Contract Net Assets at June 30, 2011
  $ 35,130  
 
 
       
OPCo
 
       
           
Total MTM Risk Management Contract Net Assets at December 31, 2010
  $ 18,264  
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
    (2,804 )
Fair Value of New Contracts at Inception When Entered During the Period (a)
    1,880  
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
       
 During the Period     (75 )
Changes in Fair Value Due to Market Fluctuations During the Period (b)
    3,180  
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
    (2,399 )
Total MTM Risk Management Contract Net Assets at June 30, 2011
    18,046  
Commodity Cash Flow Hedge Contracts
    830  
Collateral Deposits
    5,220  
Total MTM Derivative Contract Net Assets at June 30, 2011
  $ 24,096  
 
 
233

 
PSO
 
 
 
 
 
 
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2010
  $ (378 )
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
    132  
Fair Value of New Contracts at Inception When Entered During the Period (a)
    -  
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
       
  During the Period
    (7 )
Changes in Fair Value Due to Market Fluctuations During the Period (b)
    25  
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
    141  
Total MTM Risk Management Contract Net Assets (Liabilities) at June 30, 2011
    (87 )
Commodity Cash Flow Hedge Contracts
    183  
Collateral Deposits
    44  
Total MTM Derivative Contract Net Assets (Liabilities) at June 30, 2011
  $ 140  
 
       
SWEPCo
       
 
       
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2010
  $ (2,958 )
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
    2,198  
Fair Value of New Contracts at Inception When Entered During the Period (a)
    -  
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
       
  During the Period
    (7 )
Changes in Fair Value Due to Market Fluctuations During the Period (b)
    41  
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
    (339 )
Total MTM Risk Management Contract Net Assets (Liabilities) at June 30, 2011
    (1,065 )
Commodity Cash Flow Hedge Contracts
    1,397  
Collateral Deposits
    43  
Total MTM Derivative Contract Net Assets (Liabilities) at June 30, 2011
  $ 375  

(a)
Reflects fair value on primarily 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)
Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)
Relates to the net gains (losses) of those contracts that are not reflected on the Condensed Statements of Income.  These net gains (losses) are recorded as regulatory liabilities/assets.
 
 
234

 
The following tables present the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate or (require) cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
June 30, 2011
 
 
 
Remainder
 
 
 
 
 
 
 
 
 
APCo
2011 
 
2012-2014
 
2015 
 
Total
 
 
(in thousands)
Level 1 (a)
$
 32 
 
$
 2 
 
$
 - 
 
$
 34 
Level 2 (b)
 
 1,966 
 
 
 15,065 
 
 
 1,471 
 
 
 18,502 
Level 3 (c)
 
 2,211 
 
 
 2,840 
 
 
 320 
 
 
 5,371 
Total
 
 4,209 
 
 
 17,907 
 
 
 1,791 
 
 
 23,907 
Dedesignated Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
Contracts (d)
 
 1,064 
 
 
 1,598 
 
 
 - 
 
 
 2,662 
Total MTM Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
Contract Net Assets
$
 5,273 
 
$
 19,505 
 
$
 1,791 
 
$
 26,569 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Remainder
 
 
 
 
 
 
 
 
 
OPCo
2011 
 
2012-2014
 
2015 
 
Total
 
 
(in thousands)
Level 1 (a)
$
 22 
 
$
 2 
 
$
 - 
 
$
 24 
Level 2 (b)
 
 643 
 
 
 10,794 
 
 
 1,021 
 
 
 12,458 
Level 3 (c)
 
 1,525 
 
 
 1,970 
 
 
 222 
 
 
 3,717 
Total
 
 2,190 
 
 
 12,766 
 
 
 1,243 
 
 
 16,199 
Dedesignated Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
Contracts (d)
 
 738 
 
 
 1,109 
 
 
 - 
 
 
 1,847 
Total MTM Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
Contract Net Assets
$
 2,928 
 
$
 13,875 
 
$
 1,243 
 
$
 18,046 

 
 
Remainder
 
 
 
 
PSO
2011 
 
2012-2014
 
Total
 
 
(in thousands)
Level 1 (a)
$
 1 
 
$
 - 
 
$
 1 
Level 2 (b)
 
 (596)
 
 
 508 
 
 
 (88)
Level 3 (c)
 
 - 
 
 
 - 
 
 
 - 
Total MTM Risk Management
 
 
 
 
 
 
 
 
 
Contract Net Assets (Liabilities)
$
 (595)
 
$
 508 
 
$
 (87)
 
 
 
 
 
 
 
 
 
 
Remainder
 
 
 
 
SWEPCo
2011 
 
2012-2014
 
Total
 
 
(in thousands)
Level 1 (a)
$
 1 
 
$
 - 
 
$
 1 
Level 2 (b)
 
 (1,197)
 
 
 131 
 
 
 (1,066)
Level 3 (c)
 
 - 
 
 
 - 
 
 
 - 
Total MTM Risk Management
 
 
 
 
 
 
 
 
 
Contract Net Assets (Liabilities)
$
 (1,196)
 
$
 131 
 
$
 (1,065)


 
235

 
(a)
Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
(b)
Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market.
(c)
Level 3 inputs are unobservable inputs for the asset or liability.  Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.
(d)
Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.”  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This will be amortized into Revenues over the remaining life of the contracts.

Credit Risk

Counterparty credit quality and exposure of the Registrant Subsidiaries is generally consistent with that of AEP.

Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates VaR to measure commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, at June 30, 2011, a near term typical change in commodity prices is not expected to have a material effect on 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 trading portfolio for the periods indicated:

 
Six Months Ended
 
Twelve Months Ended
 
June 30, 2011
 
December 31, 2010
Company
 
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
 
(in thousands)
 
(in thousands)
APCo
 
$
109
 
$
553
 
$
147
 
$
66
 
$
124
 
$
659
 
$
193
 
$
71
OPCo
   
84
   
423
   
128
   
53
   
100
   
545
   
161
   
54
PSO
   
6
   
39
   
15
   
4
   
3
   
70
   
15
   
1
SWEPCo
   
6
   
46
   
19
   
4
   
6
   
93
   
21
   
2

Management back-tests its 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 the VaR calculations capture recent price movements, management also performs regular stress testing of the portfolio to understand the exposure to extreme price movements.  Management employs 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.  Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee or the Commercial Operations Risk Committee as appropriate.
 
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Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure.  EaR statistically quantifies the extent to which 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 the Registrant Subsidiaries’ outstanding debt as of June 30, 2011 and December 31, 2010, the estimated EaR on the Registrant Subsidiaries’ debt portfolio was as follows:

   
June 30,
 
December 31,
Company
 
2011
 
2010
   
(in thousands)
APCo
 
$
6,944 
 
$
1,165 
CSPCo
   
279 
   
178 
I&M
   
2,514 
   
274 
OPCo
   
9,597 
   
926 
PSO
   
66 
   
658 
SWEPCo
   
2,062 
   
1,027 


 
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CONTROLS AND PROCEDURES

During the second quarter of 2011, management, including the principal executive officer and principal financial officer of each of AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo (collectively, the Registrants), evaluated the Registrants’ disclosure controls and procedures.  Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of June 30, 2011, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.  The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the second quarter of 2011 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

 
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PART II.  OTHER INFORMATION

Item 1.     Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 4 incorporated herein by reference.

Item 1A.  Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2010 includes a detailed discussion of risk factors.  The information presented below amends and restates in their entirety certain of those risk factors that have been updated and should be read in conjunction with the risk factors and information disclosed in the 2010 Annual Report on Form 10-K.

RISKS RELATING TO REGULATED OPERATIONS

All of the investment in and expenses related to the Turk Plant may not be fully recovered. – Affecting AEP and SWEPCo

SWEPCo is in the process of building the John W. Turk Plant (Turk Plant) in southwest Arkansas and holds a 73% ownership interest in the planned 600 MW coal-fired generating facility.  Its construction and anticipated operation have resulted in numerous legal challenges and uncertainties, including:

·  
The validity of the air permit issued by the Arkansas Department of Environmental Quality in connection with the operation of the Turk Plant.
·  
A preliminary injunction issued by the Federal District Court for the Western District of Arkansas, and upheld by the Eighth Circuit Federal Court of Appeals, enjoining SWEPCo from completing work authorized by the permit issued by the U.S. Army Corps of Engineers, the U.S. Department of Interior and the U.S. Fish and Wildlife Service.  The preliminary injunction also raises other alleged violations of various federal and state laws.
·  
Whether SWEPCo is required to obtain APSC approval to construct the Turk Plant without pursuing authority to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates.
·  
The validity of PUCT approval of the Texas jurisdictional cost recovery and uncertainty regarding the caps on recovery included in the approval.

If SWEPCo is unable to complete the Turk Plant construction and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.
 
Rate recovery approved in Ohio may be overturned on appeal, may not provide full recovery of costs and/or may have to be returned. – Affecting AEP, CSPCo and OPCo

The PUCO issued an order in March 2009 that modified and approved the Electric Security Plans (ESPs) of CSPCo and OPCo.  The ESPs established rates in effect through 2011.  The ESP order generally authorized rate increases during the ESP period, subject to caps that limit the rate increases, and also provides a fuel adjustment clause for the three-year period of the ESPs.  The recovery includes deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges.  If the PUCO and/or the Supreme Court of Ohio reverses all or part of the rate recovery or if deferred fuel costs are not fully recovered for other reasons, it could reduce future net income and cash flows and impact financial condition.  In April 2011, the Supreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact through a remand proceeding.  Pursuant to a May 2011 PUCO order, CSPCo and OPCo implemented rates subject to refund and filed remand testimony in June 2011.  In June 2011, the Ohio Consumers’ Counsel and the IEU filed testimony recommending a complete denial of collection of any POLR charges and carrying charges on certain environmental investments collected from 2009 through 2011.  Hearings were held in July 2011.
 
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Request for rate and other recovery in Ohio for distribution service may not be approved in its entirety. – Affecting AEP, CSPCo and OPCo

In February 2011, CSPCo and OPCo filed with the PUCO for annual increases in distribution rates to be effective January 2012.  In addition to the annual increase, CSPCo and OPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets, including unrecognized equity carrying costs.  These assets would be recovered in a distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013.  If the PUCO denies all or part of the requested rate and other recovery, it could reduce future net income and cash flows and impact financial condition.

Request for rate recovery in Ohio for generation service may not be approved in its entirety. – Affecting AEP, CSPCo and OPCo

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer pricing for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  If the PUCO denies all or part of the requested rate recovery, it could reduce future net income and cash flows.  The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESPs could impact the outcome of the January 2012-May 2014 ESP, though the nature and extent of that impact is not presently known.
 
Request for rate and other recovery in Virginia for generation and distribution service may not be approved in its entirety. – Affecting AEP and APCo
In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates to be effective no later than February 2012.  APCo proposed to mitigate a portion of the requested base rate increase by maintaining current depreciation rates until the next biennial filing.  In addition, APCo filed for approval of rate adjustment clauses for various costs including environmental and renewable energy and generation costs relating to the partially completed Dresden Plant.  If the Virginia SCC denies all or part of the requested rate and other recovery, it could reduce future net income and cash flows.

Request for rate recovery in Michigan may not be approved in its entirety.  – Affecting AEP and I&M

In July 2011, I&M filed a request with the MPSC for annual increases in Michigan base rates.  The request includes an increase in depreciation rates that would result in an increase in depreciation expense.  If the MPSC denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

RISKS RELATING TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Courts adjudicating nuisance and other similar claims against us may order us to limit or reduce our CO2 emissions.  (Applies to each registrant)

In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority.  The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants.  The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants.  The Second Circuit Court of Appeals reinstated this lawsuit on appeal after the lower court had dismissed it.  The U.S. Supreme Court reversed the Court of Appeals, finding that any federal common law nuisance claim has been displaced by the provisions of the Clean Air Act that authorize Federal EPA to regulate CO2 emissions.  The Supreme Court remanded the case for consideration of plaintiffs' state law nuisance claims.

The lower courts may dismiss the state law nuisance claims without prejudice to refiling in state court.  If the court finds a basis to retain jurisdiction over those claims, it could order the defendants, including us, to limit or reduce CO2 emissions.  This or similar remedies could require us to purchase power from third parties to fulfill our commitments to supply power to our customers.  This could have a material impact on our costs.  While management believes such costs should be recoverable from customers as costs of doing business, without such recovery those costs could reduce our future net income and cash flows and harm our financial condition.
 
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Other pending cases seek damages based on allegations of federal and state common law nuisance.  If these or other future actions are resolved against us, substantial modifications of our existing coal-fired power plants could be required.  In addition, we could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay damages or penalties and/or halt operations.  Moreover, our results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.

Our costs of compliance with existing environmental laws are significant.   (Applies to each registrant.)

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety.  Approximately 90% of the electricity generated by the AEP System is produced by the combustion of fossil fuels.  Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generating plants are expected to be subject to increased regulations, controls and mitigation expenses.  Compliance with these legal requirements requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at all of our facilities and could cause us to retire generating capacity prior to the end of its estimated useful life.  These expenditures have been significant in the past and we expect that they will continue to be significant in order to comply with the current and proposed regulations.  Costs of compliance with environmental regulations could adversely affect our net income and financial position, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase.  If we retire generating plants prior to the end of their estimated useful life, there can be no assurance that we will recover the remaining costs associated with such plants.  While we expect to recover our expenditures for pollution control technologies, replacement generation and associated operating costs from customers through regulated rates (in regulated jurisdictions) or market prices, without such recovery those costs could reduce our future net income and cash flows, and possibly harm our financial condition.

RISKS RELATING TO MARKET ECONOMICS OR FINANCIAL VOLATILITY AND OTHER RISKS
 
Our financial performance may be adversely affected if we are unable to successfully operate our facilities or perform certain corporate functions.   (Applies to each registrant.)
 
Our performance is highly dependent on the successful operation of our generation, transmission and distribution facilities.  Operating these facilities involves many risks, including:

·  
Operator error and breakdown or failure of equipment or processes.
·  
Operating limitations that may be imposed by environmental or other regulatory requirements.
·  
Labor disputes.
·  
Compliance with mandatory reliability standards, including mandatory cyber security standards.
·  
Information technology failure.
·  
Cyber intrusion.
·  
Fuel supply interruptions caused by transportation constraints, adverse weather, non-performance by our suppliers and other factors.
·  
Catastrophic events such as fires, earthquakes, explosions, hurricanes, terrorism, floods or other similar occurrences.

A decrease or elimination of revenues from our electric generation, transmission and distribution facilities or an increase in the cost of operating the facilities would adversely affect our results of operations.
 
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RISKS RELATED TO STATE RESTRUCTURING

Customers have recently begun to select alternative electric generation service providers, as allowed by Ohio legislation. – Affecting AEP, CSPCo and OPCo

Under current Ohio legislation, electric generation is sold in a competitive market in Ohio, and native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service.  Competitive power suppliers are targeting retail customers by offering alternative generation service.   A growing number of commercial retail customers (primarily CSPCo’s) have switched to alternative generation providers while additional Ohio customers have provided notice of their intent to switch.  Although to date OPCo’s losses have not been significant, OPCo could experience additional customer switching in the future.  These evolving market conditions will continue to impact CSPCo's and OPCo’s results of operations.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information about purchases by AEP or its publicly-traded subsidiaries during the quarter ended June 30, 2011 of equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES
Period
 
Total Number
of Shares
Purchased
 
Average Price
Paid per Share
   
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
 
04/01/11 – 04/30/11
   
 
$
     
-
 
$
-
 
05/01/11 – 05/31/11
   
   
     
-
   
-
 
06/01/11 – 06/30/11
   
23 
(a)
 
81.80 
     
-
   
-
 

(a)
OPCo purchased 15 shares of its 4.50% cumulative preferred stock and SWEPCo purchased 8 shares of its 5.00% cumulative preferred stock in privately-negotiated transactions outside of an announced program.

 
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Item 5.  Other Information

NONE

Item 6.  Exhibits

AEP

4(d) – Amended and Restated Credit Agreement for $1.5 Billion Dated July 2011.
4(e) – Credit Agreement for $1.75 Billion Dated July 2011.

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

12 – Computation of Consolidated Ratio of Earnings to Fixed Charges.

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

31(a) – Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b) – Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

32(a) – Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
32(b) – Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 
243

 
SIGNATURE




Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.  The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.


AMERICAN ELECTRIC POWER COMPANY, INC.



             By: /s/Joseph M. Buonaiuto
             Joseph M. Buonaiuto
             Controller and Chief Accounting Officer




APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY




             By: /s/Joseph M. Buonaiuto
             Joseph M. Buonaiuto
             Controller and Chief Accounting Officer

 


 
Date:  July 29, 2011
 
244