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, 2012
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
1-3570
  
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 the registrants have submitted electronically and posted on their corporate websites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were 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, 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
  

Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric 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 26, 2012
       
American Electric Power Company, Inc.
    
484,902,556
     
($6.50 par value)
Appalachian Power Company
    
13,499,500
     
(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, 2012

   
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 of Financial Condition and Results of Operations, and Quantitative and Qualitative Disclosures About Market Risk:
 
    
American Electric Power Company, Inc. and Subsidiary Companies:
    
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
  
1
 
Condensed Consolidated Financial Statements
  
30
 
Index of Condensed Notes to Condensed Consolidated Financial Statements
  
36
       
Appalachian Power Company and Subsidiaries:
    
 
Management’s Narrative Discussion and Analysis of Results of Operations
  
80
 
Condensed Consolidated Financial Statements
  
86
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
  
92
       
Indiana Michigan Power Company and Subsidiaries:
    
 
Management’s Narrative Discussion and Analysis of Results of Operations
  
94
 
Condensed Consolidated Financial Statements
  
100
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
  
106
       
Ohio Power Company Consolidated:
    
 
Management’s Narrative Discussion and Analysis of Results of Operations
  
108
 
Condensed Consolidated Financial Statements
  
115
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
  
121
       
Public Service Company of Oklahoma:
    
 
Management’s Narrative Discussion and Analysis of Results of Operations
  
123
 
Condensed Financial Statements
  
126
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
  
132
       
Southwestern Electric Power Company Consolidated:
    
 
Management’s Narrative Discussion and Analysis of Results of Operations
  
134
 
Condensed Consolidated Financial Statements
  
139
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
  
145
       
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
  
146
       
Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries
  
201
       
Controls and Procedures
  
207
 
 
 
 
Part II.  OTHER INFORMATION
    
     
 
Item 1.
Legal Proceedings
  
208
 
Item 1A.
Risk Factors
  
208
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
  
211
 
Item 4.
Mine Safety Disclosures
  
211
 
Item 5.
Other Information
  
211
 
Item 6.
Exhibits:
  
211
         
Exhibit 10
    
         
Exhibit 12
    
         
Exhibit 31(a)
    
         
Exhibit 31(b)
    
         
Exhibit 32(a)
    
         
Exhibit 32(b)
    
         
Exhibit 95
    
         
Exhibit 101.INS
    
         
Exhibit 101.SCH
    
         
Exhibit 101.CAL
    
         
Exhibit 101.DEF
    
         
Exhibit 101.LAB
    
         
Exhibit 101.PRE
    
               
SIGNATURE
    
212

This combined Form 10-Q is separately filed by American Electric Power Company, Inc., Appalachian 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 utility holding company.
AEP Consolidated
  
AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit
  
AEP Credit, Inc., a consolidated variable interest entity of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East companies
  
APCo, I&M, KPCo and OPCo.
AEP Energy
  
AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.  BlueStar began doing business as AEP Energy, Inc. in June 2012.
AEP 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, an AEP 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.
BlueStar
  
BlueStar Energy Holdings, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.  BlueStar began doing business as AEP Energy, Inc. in June 2012.
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.
CRES
  
Competitive Retail Electric Service.
CSPCo
  
Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
DCC Fuel
  
DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC and DCC Fuel V LLC, consolidated 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 and consolidated variable interest entity of AEP.
ERCOT
  
Electric Reliability Council of Texas regional transmission organization.
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 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.
 
 
i
 
Term   Meaning
     
FERC
  
Federal Energy Regulatory Commission.
FGD
  
Flue Gas Desulfurization or scrubbers.
FTR
  
Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP
  
Accounting Principles Generally Accepted in the United States of America.
I&M
  
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IGCC
  
Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement
  
An agreement by and among APCo, 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.
KPCo
  
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
  
Kentucky Public Service Commission.
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
  
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
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 regional transmission organization.
PM
  
Particulate Matter.
POLR
  
Provider of Last Resort revenues.
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, 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 for AEP and SWEPCo.
SEC
  
U.S. Securities and Exchange Commission.
SEET
  
Significantly Excessive Earnings Test.
 
 
ii
 
Term   Meaning
     
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 regional transmission organization.
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.
TNC
  
AEP Texas North Company, an AEP electric utility subsidiary.
Transition Funding
  
AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III 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.
Turk Plant
  
John W. Turk, Jr. Plant, a 600 MW coal-fired plant under construction in Arkansas that is 73% owned by SWEPCo.
Utility Money Pool
  
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
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 2011 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 recent storms in our eastern service territory, 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 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, 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 and related assets.
·
A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
·
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 our debt.
·
Volatility and changes in markets for electricity, natural gas and other energy-related commodities.
 
 
iv
 
·
Changes in utility regulation, including the implementation of ESPs and the transition to market and expected legal separation for generation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
·
The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, 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 market prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.
·
Our ability to successfully manage negotiations with stakeholders and obtain regulatory approval to terminate or amend the Interconnection Agreement.
·
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.

The forward looking statements of AEP and its Registrant Subsidiaries speak only as of the date of this report or as of the date they are made.  AEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information.  For a more detailed discussion of these factors, see “Risk Factors” in the 2011 Annual Report and in Part II of this report.

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

EXECUTIVE OVERVIEW

Proposed June 2012 – May 2015 Ohio ESP

In March 2012, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing.  The SSO rates would be effective through May 2015.  The ESP will transition OPCo to an auction-based SSO for capacity and energy by June 2015.  The ESP also proposed to collect the Phase-In Recovery Rider from June 2013 through December 2018.  Further, the ESP proposed establishment of a non-bypassable Distribution Investment Rider through May 2015 to recover, with certain caps, post-August 2010 distribution investment.  The filing also seeks establishment of a new non-bypassable Retail Stability Rider (RSR) to recover lost generation revenues to provide financial certainty and stability during the ESP transition period.  The proposed RSR would be effective through May 2015.  Finally, the ESP proposed a storm damage recovery mechanism for the deferral of operation and maintenance costs above $5 million, effective January 2012.

Intervenors and the PUCO staff filed testimony in May 2012 in opposition to many aspects of OPCo’s ESP, including the proposed RSR and the two-tiered capacity pricing structure for CRES providers.  In addition, the PUCO staff’s testimony included a proposal to increase the vegetation management base used for calculating over/under recovery on incremental vegetation spend from $21 million to $39 million, which could increase future Other Operation and Maintenance expense by $18 million on an annual basis.  A decision from the PUCO is expected in August 2012.  See “Ohio Electric Security Plan Filing” section of Note 2.

Ohio Customer Choice

In our Ohio service territory, various CRES providers are targeting retail customers by offering alternative generation service.  As a result, in comparison to the second quarter of 2011 and the first six months of 2011, we lost approximately $56 million and $99 million, respectively, of gross margin.  We are recovering a portion of lost margins through collection of capacity revenues from CRES providers, off-system sales and new revenues from AEP Retail Energy Partners LLC, our CRES provider and member of our Generating and Marketing segment.  We have lost 34% of our Ohio load to CRES providers.  To enhance our competitive position in Ohio, AEP Retail Energy Partners LLC targets retail customers, both within and outside of our retail service territory.

Ohio Capacity Rate

In March 2012, in response to OPCo’s motion for relief, the PUCO ordered that CRES providers not qualifying for the tier one capacity billing rate of $146/MW day, which is substantially below OPCo’s current capacity cost of approximately $355/MW day, will pay a tier two capacity billing rate of $255/MW day.  In July 2012, the PUCO issued an order in the capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer its incurred capacity costs not recovered from CRES providers to the extent that the total incurred capacity costs do not exceed $188.88/MW day.  The RPM price is approximately $20/MW day through May 2013.  The order stated that the PUCO would establish an appropriate recovery mechanism in the pending June 2012 – May 2015 ESP proceeding.  The PUCO postponed implementation of the order until August 8, 2012 or until an order is issued in OPCo’s pending June 2012 – May 2015 ESP proceeding, whichever is sooner.  In July 2012, OPCo requested rehearing of the PUCO order. See “Ohio Electric Security Plan Filing” section of Note 2.
 
1
 
Proposed Corporate Separation and Termination of the Interconnection Agreement

In March 2012, OPCo filed an application with the PUCO for approval of the corporate separation of its generation assets including the transfer of generation assets to a nonregulated AEP subsidiary at net book value.  Additional filings at the FERC and other state commissions related to corporate separation are expected to be filed in the future.  If all regulatory approvals are received, our results of operations related to generation in Ohio will be determined by our ability to sell power and capacity at a profit at rates determined by the prevailing market.  If we are unable to sell power and capacity at a profit, it could reduce future net income and cash flows and impact financial condition.  A decision is pending from the PUCO.

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC.  It is unknown at this time whether the Interconnection Agreement 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.  Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future.  If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement 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.

Sustainable Cost Reductions

In April 2012, we initiated a process to identify employee repositioning opportunities and efficiencies that will result in sustainable cost savings.  We recorded a charge to expense of $13 million in the second quarter of 2012 related to the elimination of approximately 170 positions in the first phase of this process.  In May 2012, we selected one consulting firm to conduct an organizational and process optimization evaluation and a second consulting firm to evaluate our current employee benefit programs.  The second phase of this process is expected to be completed by the end of 2012 with additional cost reductions.

Storm Damage

In late June 2012 and early July 2012, our eastern service territory was significantly impacted by several severe storms.  In the second quarter of 2012, AEP recorded minimal incremental operation and maintenance expenses related to the June 2012 storms.  AEP expects to incur an estimated $230 million in total storm restoration costs in the third quarter of 2012, including an estimated $70 million in capital spending related to these storms and an estimated $160 million in incremental operation and maintenance costs.  We intend to defer the majority of the incremental operation and maintenance costs and seek future recovery.  If we are not ultimately permitted to recover these storm costs, it would reduce future net income and cash flows and impact financial condition.

Significantly Excessive Earnings Test

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off of certain pretax earnings in 2010 and a subsequent refund to customers during 2011.  In May 2011, the Industrial Energy Users-Ohio and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO’s SEET decision.  In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  Subsequent testimony and legal briefs from intervenors recommended refunds of 2010 earnings.  OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis.  The PUCO approved OPCo’s request to file the 2011 SEET on July 31, 2012 or one month after the PUCO issues an order on the 2010 SEET, whichever is later.  Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo.  See “Ohio Electric Security Plan Filing” section of Note 2.
 
2
 
Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on common equity of 11.15%.  The $149 million net annual increase reflects an increase in base rates of $178 million offset by proposed corresponding reductions of $13 million to the off-system sales sharing rider, $9 million to the PJM cost rider and $7 million to the clean coal technology rider rates.  The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.

In May 2012, the Indiana Office of Utility Consumer Counselor filed testimony that recommended an increase in base rates of $28 million, excluding reductions to certain riders, based upon a return on common equity of 9.2%.  I&M filed rebuttal testimony in May 2012 which supported an increase of $170 million in base rates, excluding reductions to certain riders.  Final hearings were held in June 2012.  A decision from the IURC is expected in the fourth quarter of 2012.  See “2011 Indiana Base Rate Case” section of Note 2.

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 scheduled to be in service in the fourth quarter of 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  See “Turk Plant” section of Note 2.

Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million based upon an 11.25% return on common equity to be effective January 2013.  The requested base rate increase includes a return on and of the Texas jurisdictional share of Turk Plant generation investment at December 2011 and total estimated transmission costs of the Turk Plant along with associated costs, including operations and maintenance costs.  It also proposed vegetation management expenditures and includes recovery of the Stall Unit.

Cook Plant

Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator.  Repair of the property damage and replacement of the turbine rotors and other equipment cost approximately $400 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.  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 would reduce future net income and cash flows and impact financial condition.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 3.

Nuclear Regulatory Commission

As a result of the nuclear plant situation in Japan following a March 2011 earthquake, the Nuclear Regulatory Commission (NRC) initiated a review of 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.  The NRC is also looking into the fuel used at eleven reactors, including the units at the Cook Plant.  Their concern relates to fuel temperatures if abnormal conditions are experienced.  We continue to monitor this issue and respond to the NRC’s inquiry, as necessary. In addition to the review by the NRC, Congress could consider legislation tightening oversight of nuclear generating facilities.  We are unable to predict the impact of potential future regulation of nuclear facilities.

Life Cycle Management Project

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects for Cook Plant Units 1 and 2.  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.
 
3
 
In Indiana, I&M requested recovery of certain project costs, including interest, through a rider effective January 2013.  In Michigan, I&M requested that the MPSC approve a Certificate of Public Convenience and Necessity and authorize I&M to defer, on an interim basis, incremental depreciation and property tax costs, including interest, along with study, analysis and development costs until the applicable costs are included in I&M’s base rates.  As of June 30, 2012, I&M has incurred $92 million related to the LCM Project.  If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

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 3 – Rate Matters, Note 5 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis” in the 2011 Annual Report.  Additionally, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies included herein.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

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.  We, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court.  The U.S. House of Representatives passed legislation called the Transparency in Regulatory Analysis of Impacts on the Nation (the TRAIN Act) that would delay implementation of certain Federal EPA rules and facilitate a comprehensive analysis of their impacts.  The Senate is considering similar legislation.  We believe that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Financial Discussion and Analysis” in the 2011 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 certain of these expenditures through market prices in deregulated jurisdictions.  If not, the costs of environmental compliance could reduce future net income and cash flows and impact financial condition.

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, 2012, the AEP System had a total generating capacity of 37,035 MWs, of which 23,900 MWs are coal-fired.  We continue to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on our coal-fired generating facilities.  Based upon our estimates, investment to meet these proposed requirements ranges from approximately $6 billion to $7 billion between 2012 and 2020.  These amounts include investments to convert 1,055 MWs of coal generation to natural gas capacity.
 
4
 
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 more stringent standards, (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.

Subject to the factors listed above and based upon our continuing evaluation, we have given notice to the applicable RTOs of our intent to retire the following plants or units of plants before or during 2016:

     
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, Units 1-4
     600  
I&M
Tanners Creek Plant, Units 1-3
     495  
KPCo
Big Sandy Plant, Unit 1
     278  
OPCo
Conesville Plant, Unit 3
     165  
OPCo
Kammer Plant
     630  
OPCo
Muskingum River Plant, Units 1-4
     840  
OPCo
Picway Plant
     100  
SWEPCo
Welsh Plant, Unit 2
     528  
Total
       4,606  

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

We are monitoring the potential impact that the proposed corporate separation of OPCo’s generation assets and the proposed termination of the Interconnection Agreement could have on the recoverability of OPCo’s generation assets.

In April 2012, we reached an agreement in principle with the Federal EPA, the State of Oklahoma and other parties to retire one coal-fired unit of PSO’s Northeastern Station no later than 2016, install emission controls on the second coal-fired Northeastern unit in 2016 and retire the second unit no later than 2026.  These two coal-fired units have a combined generating capacity of 930 MWs.  The parties are working toward a final settlement agreement.

Plans for and the timing of conversion of some of our coal units to natural gas, installing emission control equipment on other units and closure of existing units will be impacted by changes in emission requirements and demand for power.  To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows.

Environmental Control Applications

Rockport Plant

I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit one unit at its Rockport Plant with environmental controls estimated to cost $1.4 billion to comply with new requirements.  AEGCo and I&M jointly own Unit 1 and jointly lease Unit 2 of the Rockport Plant.  I&M is also evaluating options related to the maturity of the lease for Rockport Plant Unit 2 in 2022 and continues to investigate alternative compliance technologies for these Units as part of its overall compliance strategy.  As of June 30, 2012, AEGCo and I&M have incurred $10 million and $10 million, respectively, related to this project.
 
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In July 2012, certain intervenors filed testimony which recommended costs caps ranging from $1.1 billion to $1.4 billion if the IURC approved the CPCN.  In addition, the Indiana Office of Utility Consumer Counselor recommended the CPCN be denied until a more detailed and precise project plan and cost estimates are filed with the IURC.  If I&M receives approval of a CPCN, I&M will file for cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism.  An IURC decision is expected in the fourth quarter of 2012.

Big Sandy Unit 2 FGD System

In May 2012, KPCo filed a motion with the KPSC to withdraw its application seeking approval of a Certificate of Public Convenience and Necessity to retrofit Big Sandy Unit 2 with a dry FGD system.  The motion was accepted by the KPSC in May 2012.  KPCo is currently re-evaluating its needs to meet the short and long-term energy needs of its customers at the most reasonable costs.  KPCo has not determined its future plan.  As of June 30, 2012, KPCo has incurred $29 million related to the project.  Management intends to pursue recovery of all costs related to this project.  If KPCo is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

Flint Creek Plant

In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA.  The estimated cost of the project is $408 million, excluding AFUDC and company overheads.  As a joint owner of the Flint Creek Plant, SWEPCo’s portion of those costs is estimated at $204 million.  Through June 30, 2012, SWEPCo has incurred $9 million related to this project.  In June 2012, the APSC staff and the Arkansas Attorney General’s office filed testimony that recommended additional analysis be performed in order to reach a final conclusion.  The Sierra Club filed testimony that recommended the APSC deny the declaratory order.  SWEPCo is currently reviewing the testimony and will file rebuttal testimony on July 30, 2012.  A decision is pending from the APSC.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions.  The states implement and administer many of these programs and could impose additional or more stringent requirements.

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas.  BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.  CAVR will be implemented through individual state implementation plans (SIPs) or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs).  The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas and Oklahoma.  The Federal EPA finalized a FIP for Oklahoma that contains more stringent control requirements for SO2 emissions from affected units in that state.  No action has been finalized in Arkansas.  In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the Cross-State Air Pollution Rule (CSAPR) trading programs to use those programs in place of source-specific BART for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states.  As a result, depending on how the states decide to implement the CAVR, compliance with the CSAPR requirements may be sufficient to satisfy CAVR's BART requirements without the need for additional unit-specific controls.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for SO2, NOx and lead, and is currently reviewing the NAAQS for ozone and PM.  States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for our facilities as a result of those evaluations.  We cannot currently predict the nature, stringency or timing of those requirements.

Notable developments in significant CAA regulatory requirements affecting our operations are discussed in the following sections.
 
6
 
Cross-State Air Pollution Rule (CSAPR)

In August 2011, the Federal EPA issued CSAPR.  Certain revisions to the rule were finalized in March 2012.  CSAPR 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 and Louisiana are subject only to the seasonal NOx program in the rule.  Texas is 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 rule.  Numerous affected entities, states and other parties filed petitions to review the CSAPR in the United States Court of Appeals for the District of Columbia Circuit.  Several of the petitioners filed motions to stay the implementation of the rule pending judicial review.  In December 2011, the court granted the motions for stay.  Oral argument was heard in April 2012.  A supplemental rule includes Oklahoma in the seasonal NOx program.  The supplemental rule was finalized in December 2011 with an increased NOx emission budget for the 2012 compliance year.  A separate appeal of the supplemental rule has been filed, but is being held in abeyance until the court issues a decision in the main CSAPR appeal.  The Federal EPA issued a final Error Corrections Rule and further CSAPR revisions in 2012 to make corrections to state budgets and unit allocations and to remove the restrictions on interstate trading in the first phase of CSAPR.  Challenges to these rules have also been filed, but are being held in abeyance pending a decision in the main appeal.

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.  We cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In February 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal 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.  The effective date of the final rule was April 16, 2012 and compliance is required within three years.  We are participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed.   In July 2012, the Federal EPA issued a letter announcing that it will grant petitions for administrative reconsideration of certain issues related to the new source standards, including measurement issues and application of variability factors that may have an impact on the level of the standards.  The letter also announced a three-month stay in the effective date of the new source standards.  It is uncertain whether any of the information generated during the reconsideration process will affect the standards for existing sources.

The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and allows operators to exclude periods of startup and shutdown from the emissions averaging periods.  The compliance time frame remains a serious concern.  A one-year administrative extension may be available if the extension is necessary for the installation of controls or to avoid a serious reliability problem.  In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades.  We are concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines.  We are participating in petitions for review filed in the United States Court of Appeals for the District of Columbia Circuit by several organizations of which we are members.  Certain issues related to the standards for new coal-fired units have been severed from the main case and will be considered by the court on an expedited basis.  The Federal EPA’s grant of certain reconsideration petitions may alter this schedule.
 
7
 
Regional Haze

In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze SIP submitted by the State of Oklahoma through the Department of Environmental Quality.  The Federal EPA proposed 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 proposed a 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.  PSO submitted comments on the proposed action demonstrating that the cost-effectiveness calculations performed by the Federal EPA were unsound, challenging the period for compliance with the final rule and showing that the visibility improvements secured by the proposed SIP were significant and cost-effective.  The Federal EPA finalized the FIP in December 2011 that mirrored the proposed rule but established a five-year compliance schedule.  PSO filed a petition for review of the FIP in the Tenth Circuit Court of Appeals and engaged in settlement discussions with the Federal EPA, the State of Oklahoma and other parties.  In April 2012, we reached an agreement in principle that would provide for submission of a revised Regional Haze SIP requiring the retirement of one coal-fired unit of PSO’s Northeastern Station no later than 2016, installation of emission controls on the second coal-fired Northeastern unit in 2016 and retirement of the second unit no later than 2026.  The parties are working toward finalizing a settlement agreement which is intended to allow PSO to meet its compliance obligations under the regional haze and HAPs rules.

CO2 Regulation

In March 2012, the Federal EPA issued a proposal to regulate CO2 emissions from new fossil fuel-fired electricity generating units.  The proposed rule establishes a new source performance standard of 1,000 pounds of CO2 per megawatt hour of electricity generated, a rate that most natural gas combined cycle units can meet, but that is substantially below the emission rate of a new pulverized coal generator or an integrated gas combined cycle unit that uses coal for fuel.  As proposed, the rule does not apply to new gas-fired stationary combustion turbines used as peaking units, does not apply to existing, modified or reconstructed sources, and does not apply to units whose CO2 emission rate increases as a result of the addition of pollution control equipment to control criteria pollutant emissions or HAPs.  The rule is not anticipated to have a significant immediate impact on the AEP System since it does not apply to existing units or units that have already commenced construction, like our Turk Plant.  The comment period closed in June 2012.  New Source Performance Standards affect units that have not yet received permits, but complete the permitting process while the proposal is pending.  The standards have been challenged in the United States Court of Appeals for the District of Columbia Circuit.  We cannot predict the outcome of that litigation.

In June 2012, the United States Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO2 emissions from new motor vehicles and its plan to phase in regulation of CO2 emissions from stationary source under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs.  The Federal EPA also finalized a rule in June 2012 that retains the current thresholds for permitting stationary sources under the PSD and Title V operating permit programs at 100,000 tons per year for new sources and 75,000 tons per year for modified sources.  The Federal EPA also confirmed that it will re-evaluate these thresholds during its five-year review in 2016.  Our generating units are large sources of CO2 emissions and we will continue to evaluate the permitting obligations in light of these thresholds.
 
8
 
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 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.  In October 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment.  The Federal EPA has also announced its intention to complete a risk assessment of various beneficial uses of coal ash.

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 under the proposed solid waste management alternative.  Regulation of these materials as hazardous wastes would significantly increase these costs.  As the rule is not final, we are unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

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.  In June 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments.  We submitted comments in July 2012.  Issuance of a final rule is not expected until July 2013.  We are preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

Global Warming

National public policy makers and regulators in the 11 states we serve have conflicting views on global warming.  While comprehensive economy-wide regulation of CO2 emissions might be achieved through future 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.

Several states have adopted programs that directly regulate CO2 emissions from power plants, but none of these programs are currently in effect in states where we have generating facilities.  Certain of our states have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements, including Michigan, Ohio, Texas and Virginia.  We are taking steps to comply with these requirements.
 
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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 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 3.

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 reduce future net income and cash flows and impact financial condition.

For additional information on global warming, other environmental issues and the actions we are taking to address potential impacts, see Part I of the 2011 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters” and “Management’s Financial Discussion and Analysis.”
 
10
 
RESULTS OF OPERATIONS

SEGMENTS

Our primary business is the generation, transmission and distribution of electricity.  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.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

While our Utility Operations segment remains our primary business segment, the advancement of an area of our business prompted us to identify a new reportable segment.  Starting in the fourth quarter of 2011, we established our new Transmission Operations segment as described below:

Utility Operations

 
·
Generation of electricity for sale to U.S. retail and wholesale customers.
 
·
Transmission and distribution of electricity through assets owned and operated by our ten utility operating companies.

Transmission Operations

 
·
Development, construction and operation of transmission facilities through investments in our wholly-owned transmission subsidiaries that were established in 2009 and our transmission joint ventures.  These investments have PUCT-approved or FERC-approved returns on equity.

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

 
·
Nonregulated generation in ERCOT.
 
·
Marketing, risk management and retail activities in ERCOT, PJM and MISO.

The table below presents our consolidated Net Income by segment for the three and six months ended June 30, 2012 and 2011.  We reclassified prior year amounts to conform to the current year’s presentation.

   
Three Months Ended June 30,
    
Six Months Ended June 30,
  
   
2012
    
2011
    
2012
    
2011
  
   
(in millions)
  
Utility Operations
   $ 365     $ 350     $ 749     $ 724  
Transmission Operations
     8       6       17       10  
AEP River Operations
     3       (1 )     12       6  
Generation and Marketing
     (5 )     11       (6 )     12  
All Other (a)
     (8 )     (13 )     (19 )     (44 )
Net Income
   $ 363     $ 353     $ 753     $ 708  

(a)
While not considered a reportable 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 were financial derivatives which settled and expired in the fourth quarter of 2011.
 
·
Revenue sharing related to the Plaquemine Cogeneration Facility which ended in the fourth quarter of 2011.

 
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AEP CONSOLIDATED

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income increased from $353 million in 2011 to $363 million in 2012 primarily due to:

·
A decrease in other operation and maintenance expenses as a result of reduced spending.
·
A second quarter 2012 partial reversal of a 2011 deferred fuel adjustment based on an April 2012 PUCO order related to the 2009 FAC audit.

These increases were partially offset by:

·
The loss of retail customers in Ohio to various CRES providers.
·
A net decrease in regulated revenue primarily due to the elimination of POLR charges in Ohio effective June 2011, resulting from an October 2011 PUCO remand order.
·
The increase in depreciation expenses as a result of shortened depreciable lives for certain OPCo generating plants and increases in depreciation rates for APCo and I&M in February 2012 (Virginia) and April 2012 (Michigan), respectively.

Average basic shares outstanding increased from 482 million in 2011 to 485 million in 2012.  Actual shares outstanding were 485 million as of June 30, 2012.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income increased from $708 million in 2011 to $753 million in 2012 primarily due to:

·
A decrease in other operation and maintenance expenses as a result of reduced spending.
·
The first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO’s February 2012 rejection of OPCo’s modified stipulation.
·
A first quarter 2011 settlement of litigation with BOA and Enron.
·
A second quarter 2012 partial reversal of a 2011 deferred fuel adjustment based on an April 2012 PUCO order related to the 2009 FAC audit.

These increases were partially offset by:

·
The loss of retail customers in Ohio to various CRES providers.
·
A decrease in weather-related usage, primarily due to a decrease in heating degree days in the first quarter of 2012.
·
A net decrease in regulated revenue primarily due to the elimination of POLR charges in Ohio effective June 2011, resulting from an October 2011 PUCO remand order.
·
The increase in depreciation expenses as a result of shortened depreciable lives for certain OPCo generating plants and increases in depreciation rates for APCo and I&M in February 2012 (Virginia) and April 2012 (Michigan), respectively.

Average basic shares outstanding increased from 482 million in 2011 to 484 million in 2012.  Actual shares outstanding were 485 million as of June 30, 2012.

Our results of operations are discussed below by operating segment.
 
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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 electricity.  We reclassified prior year amounts to conform to the current year’s presentation.

   
Three Months Ended
    
Six Months Ended
  
   
June 30,
    
June 30,
  
   
2012
    
2011
    
2012
    
2011
  
   
(in millions)
  
Revenues
   $ 3,258     $ 3,388     $ 6,643     $ 6,912  
Fuel and Purchased Electricity
     1,096       1,230       2,365       2,527  
Gross Margin
     2,162       2,158       4,278       4,385  
Other Operation and Maintenance
     770       852       1,525       1,702  
Depreciation and Amortization
     448       398       860       791  
Taxes Other Than Income Taxes
     202       199       413       408  
Operating Income
     742       709       1,480       1,484  
Interest and Investment Income
     2       2       3       4  
Carrying Costs Income
     11       17       31       32  
Allowance for Equity Funds Used During Construction
     20       22       40       42  
Interest Expense
     (224 )     (227 )     (441 )     (459 )
Income Before Income Tax Expense and Equity
                                
Earnings
     551       523       1,113       1,103  
Income Tax Expense
     186       173       365       380  
Equity Earnings of Unconsolidated Subsidiaries
     -       -       1       1  
Net Income
   $ 365     $ 350     $ 749     $ 724  

Summary of KWH Energy Sales for Utility Operations
               
 
Three Months Ended
  
Six Months Ended
 
June 30,
  
June 30,
 
2012 
  
2011
  
2012 
2011 
 
(in millions of KWHs)
Retail:
              
Residential
 13,155 
    
 13,503 
  
 27,954 
 30,452 
Commercial
 13,087 
    
 12,913 
  
 24,353 
 24,559 
Industrial
 15,422 
    
 15,153 
  
 30,069 
 29,482 
Miscellaneous
 779 
    
 777 
  
 1,500 
 1,500 
Total Retail (a)
 42,443 
    
 42,346 
  
 83,876 
 85,993 
               
Wholesale
 8,620 
    
 10,216 
  
 17,533 
 19,367 
               
Total KWHs
 51,063 
    
 52,562 
  
 101,409 
 105,360 
               
(a) Represents energy delivered to distribution customers.

 
13
 
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,
     
2012 
  
2011 
  
2012 
  
2011 
     
(in degree days)
 
Eastern Region
                      
 
Actual - Heating (a)
  
 118 
    
 134 
    
 1,379 
    
 1,989 
 
Normal - Heating (b)
  
 165 
    
 168 
    
 1,916 
    
 1,907 
                           
 
Actual - Cooling (c)
  
 401 
    
 368 
    
 429 
    
 371 
 
Normal - Cooling (b)
  
 300 
    
 295 
    
 303 
    
 299 
                           
 
Western Region
                      
 
Actual - Heating (a)
  
 1 
    
 10 
    
 348 
    
 702 
 
Normal - Heating (b)
  
 20 
    
 21 
    
 601 
    
 600 
                           
 
Actual - Cooling (d)
  
 961 
    
 1,035 
    
 1,094 
    
 1,144 
 
Normal - Cooling (b)
  
 774 
    
 762 
    
 834 
    
 820 
                           
 
(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.

 
14
 
Second Quarter of 2012 Compared to Second Quarter of 2011

Reconciliation of Second Quarter of 2011 to Second Quarter of 2012
  
Net Income from Utility Operations
  
(in millions)
  
       
Second Quarter of 2011
   $ 350  
         
Changes in Gross Margin:
        
Retail Margins
     (15 )
Off-system Sales
     5  
Transmission Revenues
     22  
Other Revenues
     (8 )
Total Change in Gross Margin
     4  
         
Changes in Expenses and Other:
        
Other Operation and Maintenance
     82  
Depreciation and Amortization
     (50 )
Taxes Other Than Income Taxes
     (3 )
Carrying Costs Income
     (6 )
Allowance for Equity Funds Used During Construction
     (2 )
Interest Expense
     3  
Total Change in Expenses and Other
     24  
         
Income Tax Expense
     (13 )
         
Second Quarter of 2012
   $ 365  

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 electricity were as follows:

·
Retail Margins decreased $15 million primarily due to the following:
 
·
A $70 million decrease attributable to Ohio customers switching to alternative CRES providers.  This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
 
·
A $13 million net decrease in regulated revenue primarily due to the elimination of POLR charges in Ohio effective June 2011, resulting from an October 2011 PUCO remand order.
 
These decreases were partially offset by:
 
·
A $35 million increase due to OPCo’s partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
 
·
A $21 million increase in revenues related to TCC’s issuance of securitization bonds in March 2012.  This increase is partially offset by an increase in Depreciation and Amortization expense.
 
·
A $9 million rate increase for APCo.
·
Margins from Off-system Sales increased $5 million primarily due to higher PJM capacity revenues, partially offset by lower physical sales volumes and lower trading and marketing margins.
·
Transmission Revenues increased $22 million primarily due to net increases in ERCOT and increased transmission revenues for Ohio customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers partially offsets lost revenues included in Retail Margins above.
·
Other Revenues decreased $8 million primarily due to a decrease in gains on other miscellaneous sales.

 
15
 
Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses decreased $82 million primarily due to the following:
 
·
A $46 million decrease in plant outage and other plant operating and maintenance expenses.
 
·
A $30 million decrease in employee-related expenses and other reduced spending.
 
·
A $19 million decrease in storm expenses.
 
These decreases were partially offset by:
 
·
A $13 million increase due to expenses related to the 2012 sustainable cost reductions.
·
Depreciation and Amortization expenses increased $50 million primarily due to the following:
 
·
An $18 million increase due to TCC’s issuance of securitization bonds in March 2012.  The increase in TCC’s securitization related amortizations are offset within Gross Margin.
 
·
An $18 million increase due to shortened depreciable lives for certain OPCo generating plants effective December 2011.
 
·
A $14 million combined increase in depreciation for APCo and I&M primarily due to increases in depreciation rates effective February 2012 (Virginia) and April 2012 (Michigan), respectively.
 
·
A $5 million increase in amortization primarily as a result of the Virginia E&R surcharge and the Virginia Environmental Rate Adjustment Clause, both effective February 2012.
 
·
Overall higher depreciable property balances.
 
These increases were partially offset by:
 
·
A $10 million decrease due to an amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
 
·
A $5 million decrease in OPCo’s depreciation due to the third quarter 2011 plant impairment of Sporn Unit 5.
·
Carrying Costs Income decreased $6 million primarily due to OPCo’s reduction in debt carrying charges associated with the 2008 coal contract settlement for the period January 2009 through March 2012 as ordered by the PUCO in April 2012 related to the 2009 FAC audit.
·
Income Tax Expense increased $13 million primarily due to an increase in pre-tax book income.

 
16
 
Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011
 
Reconciliation of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2012
Net Income from Utility Operations
(in millions)
         
Six Months Ended June 30, 2011
  
$
 724 
  
         
Changes in Gross Margin:
        
Retail Margins
    
 (113)
  
Off-system Sales
    
 2 
  
Transmission Revenues
    
 34 
  
Other Revenues
    
 (30)
  
Total Change in Gross Margin
    
 (107)
  
         
Changes in Expenses and Other:
        
Other Operation and Maintenance
    
 177 
  
Depreciation and Amortization
    
 (69)
  
Taxes Other Than Income Taxes
    
 (5)
  
Interest and Investment Income
    
 (1)
  
Carrying Costs Income
    
 (1)
  
Allowance for Equity Funds Used During Construction
    
 (2)
  
Interest Expense
    
 18 
  
Total Change in Expenses and Other
    
 117 
  
         
Income Tax Expense
    
 15 
  
         
Six Months Ended June 30, 2012
  
$
 749 
  

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 electricity were as follows:

·
Retail Margins decreased $113 million primarily due to the following:
 
·
A $124 million decrease attributable to Ohio customers switching to alternative CRES providers.  This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
 
·
An $89 million decrease in weather-related usage in our eastern and western regions primarily due to decreases of 31% and 50%, respectively, in heating degree days.
 
·
A $17 million net decrease in regulated revenue primarily due to the elimination of POLR charges in Ohio effective June 2011, resulting from an October 2011 PUCO remand order.
 
These decreases were partially offset by:
 
·
Successful rate proceedings in our service territories which include:
   
·
A $31 million rate increase for APCo.
   
·
A $14 million rate increase for I&M.
   
·
A $9 million rate increase for PSO.
     
For the rate increases described above, $46 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
 
·
A $35 million increase due to OPCo’s second quarter 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
 
·
A $24 million increase in revenues related to TCC’s issuance of securitization bonds in March 2012.  This increase is partially offset by an increase in Depreciation and Amortization expense.
·
Margins from Off-system Sales increased $2 million primarily due to higher PJM capacity revenues, partially offset by lower physical sales volumes and lower trading and marketing margins.
·
Transmission Revenues increased $34 million primarily due to net increases in ERCOT and increased transmission revenues for Ohio customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers offsets lost revenues included in Retail Margins above.
·
Other Revenues decreased $30 million primarily due to an unfavorable regulatory order in Ohio and a decrease in gains on other miscellaneous sales.

 
17
 
Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses decreased $177 million primarily due to the following:
 
·
A $75 million decrease in plant outage and other plant operating and maintenance expenses.
 
·
A $75 million decrease in employee-related expenses and other reduced spending.
 
·
A $41 million decrease 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 $35 million decrease due to the first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO’s February 2012 rejection of OPCo’s modified stipulation.
 
·
A $16 million decrease in other storm expenses.
 
These decreases were partially offset by:
 
·
A $33 million increase due to the first quarter 2011 deferral of 2009 storm costs and the 2010 cost reduction initiatives as allowed by the WVPSC in 2011.
 
·
A $13 million increase due to expenses related to the 2012 sustainable cost reductions.
 
·
An $8 million increase in energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
·
Depreciation and Amortization expenses increased $69 million primarily due to the following:
 
·
A $32 million increase due to shortened depreciable lives for certain OPCo generating plants effective December 2011.
 
·
A $23 million increase due to TCC’s issuance of securitization bonds in March 2012.  The increase in TCC’s securitization related amortizations are offset within Gross Margin.
 
·
A $21 million combined increase in depreciation for APCo and I&M primarily due to increases in depreciation rates effective February 2012 (Virginia) and April 2012 (Michigan), respectively.
 
·
A $9 million increase in amortization primarily as a result of the Virginia E&R surcharge and the Virginia Environmental Rate Adjustment Clause, both effective February 2012.
 
·
Overall higher depreciable property balances.
 
These increases were partially offset by:
 
·
A $19 million decrease due to an amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
 
·
A $10 million decrease in OPCo’s depreciation due to the third quarter 2011 plant impairment of Sporn Unit 5.
·
Carrying Costs Income decreased $1 million primarily due to the following:
 
·
A $6 million decrease due to OPCo’s collection of carrying costs in the first quarter 2012 on phase-in FAC deferrals and line extension carrying charges recorded in 2011.
 
·
A $5 million decrease for OPCo due to a reduction in debt carrying charges associated with the 2008 coal contract settlement for the period January 2009 through March 2012 as ordered by the PUCO in April 2012 related to the 2009 FAC audit.
 
These decreases were offset by:
 
·
An $8 million increase due to the recording of debt carrying costs prior to TCC’s issuance of securitization bonds in March 2012.
 
·
A $3 million increase from carrying charges on APCo’s Dresden Plant resulting from the Virginia Generation Rate Adjustment Clause and the West Virginia Expanded Net Energy Charge.
·
Interest Expense decreased $18 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·
Income Tax Expense decreased $15 million primarily due to audit settlements for previous years and federal income tax adjustments recorded in 2011 related to prior year tax returns, partially offset by an increase in pre-tax book income.

 
18
 
TRANSMISSION OPERATIONS

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income from our Transmission Operations segment increased from $6 million in 2011 to $8 million in 2012 primarily due to an increase in investments by ETT and our wholly-owned transmission subsidiaries.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income from our Transmission Operations segment increased from $10 million in 2011 to $17 million in 2012 primarily due to an increase in investments by ETT and our wholly-owned transmission subsidiaries.

AEP RIVER OPERATIONS

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income from our AEP River Operations segment increased from a loss of $1 million in 2011 to a gain of $3 million in 2012 primarily due to flood-related expenses incurred in the second quarter of 2011 and reduced spending in 2012.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income from our AEP River Operations segment increased from $6 million in 2011 to $12 million in 2012 primarily due to flood-related expenses incurred in the second quarter of 2011 and reduced spending in 2012.

GENERATION AND MARKETING

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income from our Generation and Marketing segment decreased from a gain of $11 million in 2011 to a loss of $5 million in 2012 primarily due to the expiration of wind-related production tax credits in 2011, lower trading margins and reduced inception gains from ERCOT marketing activities.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income from our Generation and Marketing segment decreased from a gain of $12 million in 2011 to a loss of $6 million in 2012 primarily due to the expiration of wind-related production tax credits in 2011 and lower trading margins.

ALL OTHER

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income from All Other increased from a loss of $13 million in 2011 to a loss of $8 million in 2012 primarily due to a decrease in various parent related expenses.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income from All Other increased from a loss of $44 million in 2011 to a loss of $19 million in 2012 due to a loss incurred in the first quarter of 2011 related to the settlement of litigation with BOA and Enron.
 
19
 
AEP SYSTEM INCOME TAXES

Second Quarter of 2012 Compared to Second Quarter of 2011

Income Tax Expense increased $16 million primarily due to an increase in pretax book income and the expiration of wind production tax credits in 2011.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Income Tax Expense decreased $73 million primarily due to the unrealized capital loss valuation allowance related to a deferred tax asset associated with the settlement of litigation with BOA and Enron, audit settlements for previous years and a decrease in pretax book income.

FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

   
June 30, 2012
  
December 31, 2011
   
(dollars in millions)
Long-term Debt, including amounts due within one year
$
 17,302 
  
 51.6 
%
  
$
 16,516 
  
 50.3 
%
Short-term Debt
  
 1,208 
  
 3.6 
      
 1,650 
  
 5.0 
  
Total Debt
  
 18,510 
  
 55.2 
      
 18,166 
  
 55.3 
  
AEP Common Equity
  
 15,007 
  
 44.8 
      
 14,664 
  
 44.7 
  
Noncontrolling Interests
  
 1 
  
 - 
      
 1 
  
 - 
  
                       
Total Debt and Equity Capitalization
$
 33,518 
  
 100.0 
%
  
$
 32,831 
  
 100.0 
%

Our ratio of debt-to-total capital decreased from 55.3% at December 31, 2011 to 55.2% at June 30, 2012.  Long-term debt outstanding increased due to the March 2012 issuance of $800 million of securitization bonds.

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, 2012, we had $3.25 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-and-leaseback or leasing agreements or common stock.
 
20
 
Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At June 30, 2012, our available liquidity was approximately $2.8 billion as illustrated in the table below:

     
Amount
  
Maturity
     
(in millions)
    
Commercial Paper Backup:
          
 
Revolving Credit Facility
  
$
 1,500 
  
June 2015
 
Revolving Credit Facility
    
 1,750 
  
July 2016
Total
    
 3,250 
    
Cash and Cash Equivalents
    
 297 
    
Total Liquidity Sources
    
 3,547 
    
Less:
AEP Commercial Paper Outstanding
    
 550 
    
 
Letters of Credit Issued
    
 167 
    
             
Net Available Liquidity
  
$
 2,830 
    

We have credit facilities totaling $3.25 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.

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 2012 was $1.2 billion.  The weighted-average interest rate for our commercial paper during 2012 was 0.46%.

Securitized Accounts Receivables

In June 2012, we renewed our receivables securitization agreement.  The agreement provides a commitment of $700 million from bank conduits to purchase receivables.  A commitment of $385 million expires in June 2013 and the remaining commitment of $315 million expires in June 2015.

Securitization of Regulatory Assets

In March 2012, West Virginia passed securitization legislation, which allows the WVPSC to establish a regulatory framework to securitize certain deferred Expanded Net Energy Charge (ENEC) balances and other ENEC related assets.  APCo and WPCo anticipate filing, in the third quarter of 2012, a request for a financing order with the WVPSC pursuant to the securitization legislation to securitize approximately $400 million.  See “APCo’s and WPCo’s Expanded Net Energy Charge (ENEC) Filing” section of Note 2.

OPCo plans to file, in the third quarter of 2012, an application with the PUCO requesting securitization of the Distribution Asset Recovery Rider (DARR) balance.  As of June 30, 2012, OPCo’s DARR balance was $309 million, including $145 million of unrecognized equity carrying costs.  Currently, the DARR is being recovered through 2018.
 
21
 
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 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, 2012, this contractually-defined percentage was 50%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  At June 30, 2012, we complied with all of the covenants contained in these credit agreements.  In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements and in a majority of our non-exchange traded commodity contracts which would permit the lenders and counterparties to declare the outstanding amounts payable.  However, a default under our non-exchange traded commodity contracts does not cause an event of default under our revolving credit agreements.

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

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  At June 30, 2012, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.47 per share in July 2012.  Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time.  Our income derives from our common stock equity in the earnings of our utility subsidiaries.  Various financing arrangements 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 financing arrangements 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.
 
22
 
CASH FLOW

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

 
Six Months Ended
  
 
June 30,
  
 
2012
  
2011
  
 
(in millions)
  
Cash and Cash Equivalents at Beginning of Period
   $ 221     $ 294  
Net Cash Flows from Operating Activities
     1,713       1,732  
Net Cash Flows Used for Investing Activities
     (1,530 )     (1,280 )
Net Cash Flows Used for Financing Activities
     (107 )     (329 )
Net Increase in Cash and Cash Equivalents
     76       123  
Cash and Cash Equivalents at End of Period
   $ 297     $ 417  

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,
  
 
2012
  
2011
  
 
(in millions)
  
Net Income
   $ 753     $ 708  
Depreciation and Amortization
     883       813  
Other
     77       211  
Net Cash Flows from Operating Activities
   $ 1,713     $ 1,732  

Net Cash Flows from Operating Activities were $1.7 billion in 2012 consisting primarily of Net Income of $753 million and $883 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.  A significant change in other items includes the favorable impact of a decrease in accounts receivable and the unfavorable impact of an increase in fuel inventory due to the mild winter weather.  Cash was also used to pay real and personal property taxes and to reduce accounts payable.  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 and an increase in tax versus book temporary differences from operations.

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.
 
23
 
Investing Activities
 
 
Six Months Ended
  
 
June 30,
  
 
2012
  
2011
  
 
(in millions)
  
Construction Expenditures
   $ (1,371 )   $ (1,113 )
Acquisitions of Nuclear Fuel
     (11 )     (93 )
Acquisitions of Assets/Businesses
     (88 )     (10 )
Acquisition of Cushion Gas from BOA
     -       (214 )
Proceeds from Sales of Assets
     8       94  
Other
     (68 )     56  
Net Cash Flows Used for Investing Activities
   $ (1,530 )   $ (1,280 )

Net Cash Flows Used for Investing Activities were $1.5 billion in 2012 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments.  Acquisitions of Assets/Businesses include our March 2012 purchase of BlueStar for $70 million.

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.
 
Financing Activities

 
Six Months Ended
  
 
June 30,
  
 
2012
  
2011
  
 
(in millions)
  
Issuance of Common Stock, Net
   $ 50     $ 49  
Issuance of Debt, Net
     332       104  
Dividends Paid on Common Stock
     (458 )     (446 )
Other
     (31 )     (36 )
Net Cash Flows Used for Financing Activities
   $ (107 )   $ (329 )

Net Cash Flows Used for Financing Activities in 2012 were $107 million.  Our net debt issuances were $332 million. The net issuances included issuances of $800 million of securitization bonds, $275 million of senior unsecured notes and $197 million of notes payable and other debt offset by retirements of $234 million of senior unsecured and other debt notes, $155 million of pollution control bonds, $98 million of securitization bonds and a decrease in short-term borrowing of $442 million.  We paid common stock dividends of $458 million.  See Note 10 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

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.

In July 2012, I&M retired $9 million of Notes Payable related to DCC Fuel.

In July 2012, TCC retired $73 million of Securitization Bonds.
 
24
 
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 guidelines restrict 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,
  
 
2012
  
2011
  
 
(in millions)
  
Rockport Plant Unit 2 Future Minimum Lease Payments
   $ 1,552     $ 1,626  
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 2011 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2011 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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Financial Discussion and Analysis” in the 2011 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.

ACCOUNTING PRONOUNCEMENTS

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes.  The FASB is currently working on several projects including revenue recognition, financial instruments, leases, insurance, hedge accounting and consolidation policy.  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 future net income and financial position.

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 as we occasionally 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 conducts marketing, risk management and retail activities in ERCOT, PJM and MISO.  This segment is exposed to certain market risks as a marketer of wholesale and retail 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.
 
25
 
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 and Finance groups in accordance with our established risk management policies as 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 Chief Operating Officer, 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.
 
26
 
The following table summarizes the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2011:

MTM Risk Management Contract Net Assets (Liabilities)
  
Six Months Ended June 30, 2012
  
   
         
Generation
        
   
Utility
    
and
        
   
Operations
    
Marketing
    
Total
  
   
(in millions)
  
Total MTM Risk Management Contract Net Assets
                  
at December 31, 2011
   $ 59     $ 132     $ 191  
(Gain) Loss from Contracts Realized/Settled During the Period and
                        
Entered in a Prior Period
     14       (14 )     -  
Fair Value of New Contracts at Inception When Entered During the
                        
Period (a)
     5       9       14  
Changes in Fair Value Due to Market Fluctuations During the
                        
Period (b)
     5       (1 )     4  
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
     4       -       4  
Total MTM Risk Management Contract Net Assets
                        
at June 30, 2012
   $ 87     $ 126       213  
                         
Commodity Cash Flow Hedge Contracts
                     (22 )
Interest Rate and Foreign Currency Cash Flow Hedge Contracts
                     (35 )
Fair Value Hedge Contracts
                     2  
Collateral Deposits
                     76  
Total MTM Derivative Contract Net Assets at June 30, 2012
                   $ 234  

(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.

See Note 7 – Derivatives and Hedging and Note 8 – 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.
 
27
 
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, 2012, our credit exposure net of collateral to sub investment grade counterparties was approximately 6%, 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, 2012, 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
  
$
 739 
  
$
 2 
  
$
 737 
    
 2 
  
$
 313 
Split Rating
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
Noninvestment Grade
    
 12 
    
 2 
    
 10 
    
 1 
    
 10 
No External Ratings:
                              
 
Internal Investment Grade
    
 168 
    
 - 
    
 168 
    
 1 
    
 42 
 
Internal Noninvestment Grade
    
 58 
    
 10 
    
 48 
    
 1 
    
 35 
Total as of June 30, 2012
  
$
 977 
  
$
 14 
  
$
 963 
    
 5 
  
$
 400 
                                 
Total as of December 31, 2011
  
$
 960 
  
$
 19 
  
$
 941 
    
 5 
  
$
 348 

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, 2012, a near term typical change in commodity prices is not expected to have a material effect on our net income, cash flows or financial condition.

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

VaR Model

Six Months Ended
  
Twelve Months Ended
June 30, 2012
  
December 31, 2011
End
  
High
  
Average
  
Low
  
End
  
High
  
Average
  
Low
(in millions)
  
(in millions)
$
- 
  
$
1 
  
$
- 
  
$
- 
  
$
- 
  
$
2 
  
$
- 
  
$
- 

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.
 
28
 
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, 2012 and December 31, 2011, the estimated EaR on our debt portfolio for the following twelve months was $37 million and $29 million, respectively.
 
29
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
  
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
  
For the Three and Six Months Ended June 30, 2012 and 2011
  
(in millions, except per-share and share amounts)
  
(Unaudited)
  
                         
   
Three Months Ended
    
Six Months Ended
  
   
2012
    
2011
    
2012
    
2011
  
REVENUES
                        
Utility Operations
   $ 3,235     $ 3,360     $ 6,598     $ 6,857  
Other Revenues
     316       249       578       482  
TOTAL REVENUES
     3,551       3,609       7,176       7,339  
EXPENSES
                                
Fuel and Other Consumables Used for Electric Generation
     904       980       1,957       2,036  
Purchased Electricity for Resale
     268       287       528       562  
Other Operation
     719       697       1,375       1,383  
Maintenance
     252       316       514       581  
Depreciation and Amortization
     460       410       883       813  
Taxes Other Than Income Taxes
     207       202       424       415  
TOTAL EXPENSES
     2,810       2,892       5,681       5,790  
                                 
OPERATING INCOME
     741       717       1,495       1,549  
                                 
Other Income (Expense):
                                
Interest and Investment Income
     2       3       4       5  
Carrying Costs Income
     11       17       31       32  
Allowance for Equity Funds Used During Construction
     24       23       47       43  
Interest Expense
     (235 )     (239 )     (464 )     (481 )
                                 
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
     543       521       1,113       1,148  
                                 
Income Tax Expense
     190       174       379       452  
Equity Earnings of Unconsolidated Subsidiaries
     10       6       19       12  
                                 
NET INCOME
     363       353       753       708  
                                 
Net Income Attributable to Noncontrolling Interests
     1       1       2       2  
                                 
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS
     362       352       751       706  
                                 
Preferred Stock Dividend Requirements of Subsidiaries
     -       -       -       1  
                                 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
   $ 362     $ 352     $ 751     $ 705  
                                 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
     484,500,029       481,928,494       484,164,065       481,538,549  
                                 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
                                
SHAREHOLDERS
   $ 0.75     $ 0.73     $ 1.55     $ 1.46  
                                 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
     484,860,690       482,203,255       484,554,779       481,786,698  
                                 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
                                
SHAREHOLDERS
   $ 0.75     $ 0.73     $ 1.55     $ 1.46  
                                 
CASH DIVIDENDS DECLARED PER SHARE
   $ 0.47     $ 0.46     $ 0.94     $ 0.92  
                                 
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 36.
                                

 
30
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
  
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
  
For the Three and Six Months Ended June 30, 2012 and 2011
  
(in millions)
  
(Unaudited)
  
                         
   
Three Months Ended
    
Six Months Ended
  
   
2012
    
2011
    
2012
    
2011
  
Net Income
   $ 363     $ 353     $ 753     $ 708  
                                 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                                
Cash Flow Hedges, Net of Tax of $5 and $2 for the Three Months Ended
                                
June 30, 2012 and 2011, Respectively, and $11 and $3 for the Six
                                
Months Ended June 30, 2012 and 2011, Respectively
     (10 )     5       (21 )     6  
Securities Available for Sale, Net of Tax of $- and $- for the Three Months
                                
Ended June 30, 2012 and 2011, Respectively, and $1 and $- for the
                                
Six Months Ended June 30, 2012 and 2011, Respectively
     (1 )     -       1       1  
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $4
                                
and $3 for the Three Months Ended June 30, 2012 and 2011,
                                
Respectively, and $8 and $6 for the Six Months Ended June 30,
                                
2012 and 2011, Respectively
     8       6       15       12  
                                 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
     (3 )     11       (5 )     19  
                                 
TOTAL COMPREHENSIVE INCOME
     360       364       748       727  
                                 
Total Comprehensive Income Attributable to Noncontrolling Interests
     1       1       2       2  
                                 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
                                
SHAREHOLDERS
     359       363       746       725  
                                 
Preferred Stock Dividend Requirements of Subsidiaries
     -       -       -       1  
                                 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
                                
COMMON SHAREHOLDERS
   $ 359     $ 363     $ 746     $ 724  
                                 
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 36.
  

 
31
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 30, 2012 and 2011
(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, 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 
                                         
Net Income
                    
 706 
          
 2 
    
 708 
Other Comprehensive Income
                          
 19 
          
 19 
TOTAL EQUITY – JUNE 30, 2011
  
 502 
  
$
 3,266 
  
$
 5,932 
  
$
 5,103 
  
$
 (362)
  
$
 - 
  
$
 13,939 
                                         
TOTAL EQUITY – DECEMBER 31, 2011
  
 504 
  
$
 3,274 
  
$
 5,970 
  
$
 5,890 
  
$
 (470)
  
$
 1 
  
$
 14,665 
                                         
Issuance of Common Stock
  
 1 
    
 10 
    
 40 
                      
 50 
Common Stock Dividends
                    
 (456)
          
 (2)
    
 (458)
Other Changes in Equity
              
 3 
                      
 3 
Subtotal – Equity
                                      
 14,260 
                                         
Net Income
                    
 751 
          
 2 
    
 753 
Other Comprehensive Loss
                          
 (5)
          
 (5)
TOTAL EQUITY – JUNE 30, 2012
  
 505 
  
$
 3,284 
  
$
 6,013 
  
$
 6,185 
  
$
 (475)
  
$
 1 
  
$
 15,008 
                                         
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 36.

 
32
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2012 and December 31, 2011
(in millions)
(Unaudited)
 
   
2012 
  
2011 
CURRENT ASSETS
            
Cash and Cash Equivalents
  
$
 297 
  
$
 221 
Other Temporary Investments
            
 
(June 30, 2012 and December 31, 2011 Amounts Include $279 and $281, Respectively, Related to Transition Funding and EIS)
    
 297 
    
 294 
Accounts Receivable:
            
 
Customers
    
 674 
    
 690 
 
Accrued Unbilled Revenues
    
 129 
    
 106 
 
Pledged Accounts Receivable – AEP Credit
    
 910 
    
 920 
 
Miscellaneous
    
 84 
    
 150 
 
Allowance for Uncollectible Accounts
    
 (35)
    
 (32)
   
Total Accounts Receivable
    
 1,762 
    
 1,834 
Fuel
    
 837 
    
 657 
Materials and Supplies
    
 657 
    
 635 
Risk Management Assets
    
 219 
    
 193 
Accrued Tax Benefits
    
 46 
    
 51 
Regulatory Asset for Under-Recovered Fuel Costs
    
 126 
    
 65 
Margin Deposits
    
 63 
    
 67 
Prepayments and Other Current Assets
    
 179 
    
 165 
TOTAL CURRENT ASSETS
    
 4,483 
    
 4,182 
             
PROPERTY, PLANT AND EQUIPMENT
            
Electric:
            
 
Generation
    
 25,382 
    
 24,938 
 
Transmission
    
 9,372 
    
 9,048 
 
Distribution
    
 15,148 
    
 14,783 
Other Property, Plant and Equipment (Including Nuclear Fuel and Coal Mining)
    
 3,862 
    
 3,780 
Construction Work in Progress
    
 3,020 
    
 3,121 
Total Property, Plant and Equipment
    
 56,784 
    
 55,670 
Accumulated Depreciation and Amortization
    
 18,956 
    
 18,699 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    
 37,828 
    
 36,971 
             
OTHER NONCURRENT ASSETS
            
Regulatory Assets
    
 5,277 
    
 6,026 
Securitized Transition Assets
    
 2,241 
    
 1,627 
Spent Nuclear Fuel and Decommissioning Trusts
    
 1,658 
    
 1,592 
Goodwill
    
 90 
    
 76 
Long-term Risk Management Assets
    
 439 
    
 403 
Deferred Charges and Other Noncurrent Assets
    
 1,405 
    
 1,346 
TOTAL OTHER NONCURRENT ASSETS
    
 11,110 
    
 11,070 
             
TOTAL ASSETS
  
$
 53,421 
  
$
 52,223 
             
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 36.
            
 
 
33
 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2012 and December 31, 2011
(dollars in millions)
(Unaudited)
 
   
2012 
  
2011 
CURRENT LIABILITIES
    
Accounts Payable
  
$
 906 
  
$
 1,095 
Short-term Debt:
            
 
Securitized Debt for Receivables - AEP Credit
      
 658 
    
 666 
 
Other Short-term Debt
      
 550 
    
 984 
   
Total Short-term Debt
      
 1,208 
    
 1,650 
Long-term Debt Due Within One Year
            
 
(June 30, 2012 and December 31, 2011 Amounts Include $368 and $293, Respectively, Related to Transition Funding, DCC Fuel and Sabine)
    
 1,983 
    
 1,433 
Risk Management Liabilities
    
 165 
    
 150 
Customer Deposits
    
 293 
    
 289 
Accrued Taxes
    
 617 
    
 717 
Accrued Interest
    
 281 
    
 279 
Regulatory Liability for Over-Recovered Fuel Costs
    
 84 
    
 8 
Other Current Liabilities
    
 870 
    
 990 
TOTAL CURRENT LIABILITIES
    
 6,407 
    
 6,611 
             
NONCURRENT LIABILITIES
            
Long-term Debt
            
 
(June 30, 2012 and December 31, 2011 Amounts Include $2,400 and $1,674, Respectively, Related to Transition Funding, DCC Fuel and Sabine)
    
 15,319 
    
 15,083 
Long-term Risk Management Liabilities
    
 259 
    
 195 
Deferred Income Taxes
    
 8,627 
    
 8,227 
Regulatory Liabilities and Deferred Investment Tax Credits
    
 3,615 
    
 3,195 
Asset Retirement Obligations
    
 1,523 
    
 1,472 
Employee Benefits and Pension Obligations
    
 1,729 
    
 1,801 
Deferred Credits and Other Noncurrent Liabilities
    
 934 
    
 974 
TOTAL NONCURRENT LIABILITIES
    
 32,006 
    
 30,947 
             
TOTAL LIABILITIES
    
 38,413 
    
 37,558 
             
Rate Matters (Note 2)
            
Commitments and Contingencies (Note 3)
            
             
EQUITY
            
Common Stock – Par Value – $6.50 Per Share:
            
     
2012 
  
2011 
              
 
Shares Authorized
600,000,000 
  
600,000,000 
              
 
Shares Issued
505,165,281 
  
503,759,460 
              
(20,336,592 Shares were Held in Treasury at June 30, 2012 and December 31, 2011)
    
 3,284 
    
 3,274 
Paid-in Capital
    
 6,013 
    
 5,970 
Retained Earnings
    
 6,185 
    
 5,890 
Accumulated Other Comprehensive Income (Loss)
    
 (475)
    
 (470)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY
    
 15,007 
    
 14,664 
             
Noncontrolling Interests
    
 1 
    
 1 
             
TOTAL EQUITY
    
 15,008 
    
 14,665 
             
TOTAL LIABILITIES AND EQUITY
  
$
 53,421 
  
$
 52,223 
             
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 36.
            

 
34
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2012 and 2011
(in millions)
(Unaudited)
 
   
2012 
  
2011 
OPERATING ACTIVITIES
            
Net Income
  
$
 753 
  
$
 708 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
            
 
Depreciation and Amortization
    
 883 
    
 813 
 
Deferred Income Taxes
    
 417 
    
 525 
 
Gain on Settlement with BOA and Enron
    
 - 
    
 (51)
 
Settlement of Litigation with BOA and Enron
    
 - 
    
 (211)
 
Carrying Costs Income
    
 (31)
    
 (32)
 
Allowance for Equity Funds Used During Construction
    
 (47)
    
 (43)
 
Mark-to-Market of Risk Management Contracts
    
 8 
    
 61 
 
Amortization of Nuclear Fuel
    
 64 
    
 72 
 
Property Taxes
    
 68 
    
 62 
 
Fuel Over/Under-Recovery, Net
    
 91 
    
 (93)
 
Change in Other Noncurrent Assets
    
 (80)
    
 (11)
 
Change in Other Noncurrent Liabilities
    
 31 
    
 83 
 
Changes in Certain Components of Working Capital:
            
   
Accounts Receivable, Net
    
 93 
    
 53 
   
Fuel, Materials and Supplies
    
 (199)
    
 146 
   
Accounts Payable
    
 (100)
    
 (87)
   
Accrued Taxes, Net
    
 (92)
    
 (198)
   
Other Current Assets
    
 (7)
    
 (9)
   
Other Current Liabilities
    
 (139)
    
 (56)
Net Cash Flows from Operating Activities
    
 1,713 
    
 1,732 
             
INVESTING ACTIVITIES
            
Construction Expenditures
    
 (1,371)
    
 (1,113)
Change in Other Temporary Investments, Net
    
 (1)
    
 11 
Purchases of Investment Securities
    
 (546)
    
 (645)
Sales of Investment Securities
    
 517 
    
 712 
Acquisitions of Nuclear Fuel
    
 (11)
    
 (93)
Acquisitions of Assets/Businesses
    
 (88)
    
 (10)
Acquisition of Cushion Gas from BOA
    
 - 
    
 (214)
Proceeds from Sales of Assets
    
 8 
    
 94 
Other Investing Activities
    
 (38)
    
 (22)
Net Cash Flows Used for Investing Activities
    
 (1,530)
    
 (1,280)
             
FINANCING ACTIVITIES
            
Issuance of Common Stock, Net
    
 50 
    
 49 
Issuance of Long-term Debt
    
 1,261 
    
 1,074 
Commercial Paper and Credit Facility Borrowings
    
 21 
    
 357 
Change in Short-term Debt, Net
    
 (425)
    
 566 
Retirement of Long-term Debt
    
 (487)
    
 (1,263)
Commercial Paper and Credit Facility Repayments
    
 (38)
    
 (630)
Principal Payments for Capital Lease Obligations
    
 (36)
    
 (35)
Dividends Paid on Common Stock
    
 (458)
    
 (446)
Dividends Paid on Cumulative Preferred Stock
    
 - 
    
 (1)
Other Financing Activities
    
 5 
    
 - 
Net Cash Flows Used for Financing Activities
    
 (107)
    
 (329)
             
Net Increase in Cash and Cash Equivalents
    
 76 
    
 123 
Cash and Cash Equivalents at Beginning of Period
    
 221 
    
 294 
Cash and Cash Equivalents at End of Period
  
$
 297 
  
$
 417 
             
SUPPLEMENTARY INFORMATION
            
Cash Paid for Interest, Net of Capitalized Amounts
  
$
 444 
  
$
 442 
Net Cash Paid (Received) for Income Taxes
    
 (42)
    
 15 
Noncash Acquisitions Under Capital Leases
    
 33 
    
 28 
Construction Expenditures Included in Current Liabilities at June 30,
    
 255 
    
 292 
Noncash Assumption of Liabilities Related to Acquisitions
    
 56 
    
 - 
             
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 36.
            

 
35
 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

 
36
 
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, 2012 is not necessarily indicative of results that may be expected for the year ending December 31, 2012.  The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2011 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 28, 2012.

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, variable interests held by related parties 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, 2012 and 2011 were $36 million and $30 million, respectively, and for the six months ended June 30, 2012 and 2011 were $91 million and $64 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on our condensed balance sheets.
 
37
 
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 payments to the protected cell for the three months ended June 30, 2012 and 2011 was $0 and $80 thousand, respectively, and for the six months ended June 30, 2012 and 2011 was $15 million and $30 million, respectively.  See the tables below for the classification of the protected cell’s assets and liabilities on our condensed balance sheets.  The amount reported as equity is the protected cell’s policy holders’ surplus.

I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC and DCC Fuel V 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.  Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the leases for the three months ended June 30, 2012 and 2011 were $42 million and $38 million, respectively, and for the six months ended June 30, 2012 and 2011 were $59 million and $43 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 respective lease terms, which do not exceed 54 months.  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 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 balance sheets.  See “Securitized Accounts Receivable – AEP Credit” section of Note 10.

Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.  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 $2.4 billion and $1.7 billion at June 30, 2012 and December 31, 2011, respectively, and are included in current and long-term debt on the condensed balance sheets.  Transition Funding has securitized transition assets of $2.2 billion and $1.6 billion at June 30, 2012 and December 31, 2011, respectively, which are presented separately on the face of the condensed 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 assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs.  See the tables below for the classification of Transition Funding’s assets and liabilities on our condensed balance sheets.
 
38
 
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, 2012
(in millions)
                                 
                         
TCC
    
 
SWEPCo
  
I&M
  
Protected Cell
      
Transition
    
 
Sabine
  
DCC Fuel
  
of EIS
  
AEP Credit
  
Funding
    
ASSETS
                                
Current Assets
   $ 67     $ 147     $ 125     $ 897     $ 235    
Net Property, Plant and Equipment
     170       241       -       -       -    
Other Noncurrent Assets
     57       143       5       1       2,293  
(a)
Total Assets
   $ 294     $ 531     $ 130     $ 898     $ 2,528    
                                           
LIABILITIES AND EQUITY
                                          
Current Liabilities
   $ 42     $ 127     $ 43     $ 851     $ 303    
Noncurrent Liabilities
     252       404       67       1       2,207    
Equity
     -       -       20       46       18    
Total Liabilities and Equity
   $ 294     $ 531     $ 130     $ 898     $ 2,528    

(a)       Includes an intercompany item eliminated in consolidation of $92 million.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2011
(in millions)
                             
                         
TCC
 
SWEPCo
  
I&M
  
Protected Cell
      
Transition
 
Sabine
  
DCC Fuel
  
of EIS
  
AEP Credit
  
Funding
ASSETS
                            
Current Assets
   $ 48     $ 118     $ 121     $ 910     $ 220
Net Property, Plant and Equipment
     154       188       -       -       -
Other Noncurrent Assets
     42       118       6       1       1,580
Total Assets
   $ 244     $ 424     $ 127     $ 911     $ 1,800
                                       
LIABILITIES AND EQUITY
                                      
Current Liabilities
   $ 68     $ 103     $ 40     $ 864     $ 229
Noncurrent Liabilities
     176       321       71       1       1,557
Equity
     -       -       16       46       14
Total Liabilities and Equity
   $ 244     $ 424     $ 127     $ 911     $ 1,800

 
39
 
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 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, 2012 and 2011 were $20 million and $15 million, respectively and for the six months ended June 30, 2012 and 2011 were $34 million and $29 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 balance sheets.

Our investment in DHLC was:

 
June 30, 2012
  
December 31, 2011
  
 
As Reported on
  
Maximum
  
As Reported on
  
Maximum
  
 
the Balance Sheet
  
Exposure
  
the Balance Sheet
  
Exposure
  
 
(in millions)
  
Capital Contribution from SWEPCo
   $ 8     $ 8     $ 8     $ 8  
Retained Earnings
     1       1       1       1  
SWEPCo's Guarantee of Debt
     -       57       -       52  
                                 
Total Investment in DHLC
   $ 9     $ 66     $ 9     $ 61  

We and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH).  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, through its operating companies, a high-voltage transmission line project in the PJM region.  PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy.  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 balance sheets.  We and FirstEnergy share the returns and losses equally in PATH-WV.  Our subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements.  As of June 30, 2012, PATH-WV had no debt outstanding.  However, if 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, 2012
  
December 31, 2011
  
   
As Reported on
  
Maximum
  
As Reported on
  
Maximum
  
   
the Balance Sheet
  
Exposure
  
the Balance Sheet
  
Exposure
  
       
(in millions)
      
Capital Contribution from AEP
   $ 19   $ 19   $ 19   $ 19  
Retained Earnings
     12     12     10     10  
                           
Total Investment in PATH-WV
   $ 31   $ 31   $ 29   $ 29  
 
 
40
 
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.

The following tables present our basic and diluted EPS calculations included on our condensed statements of income:

   
Three Months Ended June 30,
   
2012
    
2011
   
(in millions, except per share data)
       
$/share
        
$/share
Earnings Attributable to AEP Common Shareholders
   $ 362           $ 352      
                           
Weighted Average Number of Basic Shares Outstanding
     484.5     $ 0.75       481.9     $ 0.73
Weighted Average Dilutive Effect of:
                              
Stock Options
     0.1       -       0.1       -
Restricted Stock Units
     0.3       -       0.2       -
Weighted Average Number of Diluted Shares Outstanding
     484.9     $ 0.75       482.2     $ 0.73

   
Six Months Ended June 30,
   
2012
    
2011
   
(in millions, except per share data)
       
$/share
        
$/share
Earnings Attributable to AEP Common Shareholders
   $ 751           $ 705      
                           
Weighted Average Number of Basic Shares Outstanding
     484.2     $ 1.55       481.5     $ 1.46
Weighted Average Dilutive Effect of:
                              
Stock Options
     0.1       -       0.1       -
Restricted Stock Units
     0.3       -       0.2       -
Weighted Average Number of Diluted Shares Outstanding
     484.6     $ 1.55       481.8     $ 1.46

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

Options to purchase 10,000 and 70,050 shares of common stock at June 30, 2012 and 2011, respectively, 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.
 
41
 
2.  RATE MATTERS

As discussed in the 2011 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within our 2011 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 2012 and updates the 2011 Annual Report.
 
Regulatory Assets Not Yet Being Recovered

   
June 30,
    
December 31,
  
   
2012
    
2011
  
   
(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
            
Storm Related Costs
   $ 24     $ 24  
Economic Development Rider
     13       13  
Regulatory Assets Currently Not Earning a Return
                
Virginia Environmental Rate Adjustment Clause
     22       18  
Mountaineer Carbon Capture and Storage Product Validation Facility
     14       14  
Special Rate Mechanism for Century Aluminum
     13       13  
Litigation Settlement
     11       11  
Storm Related Costs
     8       10  
Virginia Deferred Wind Power Costs
     4       38  
Other Regulatory Assets Not Yet Being Recovered
     26       14  
Total Regulatory Assets Not Yet Being Recovered
   $ 135     $ 155  

OPCo Rate Matters

Ohio Electric Security Plan Filing

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011.  OPCo collected the 2009 annualized revenue increase over the last nine months of 2009.  The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018.  See the “January 2012 – May 2016 ESP as Rejected by the PUCO” section below.  The PUCO’s March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO.

In October 2011, the PUCO issued an order in the remand proceeding.  As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011.  In February 2012, the Ohio Consumers’ Counsel and the Industrial Energy Users-Ohio (IEU) filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which if ordered could total up to $698 million, excluding carrying costs.
 
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In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off of certain pretax earnings in 2010 and a subsequent refund to customers during 2011.  In May 2011, the IEU and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO’s SEET decision.  The OEG’s appeal seeks the inclusion of off-system sales (OSS) in the calculation of SEET which, if ordered, could require an additional refund of $22 million based on the PUCO approved SEET calculation.  The IEU’s appeal also sought the inclusion of OSS as well as other items in the determination of SEET, but did not quantify the amount.  Oral arguments were held in March 2012 and management is unable to predict the outcome of the appeals.  If the Supreme Court of Ohio ultimately determines that additional amounts should be refunded, it could reduce future net income and cash flows and impact financial condition.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings, which included OSS in the SEET calculation.  In December 2011, the PUCO staff filed testimony that recommended a $23 million refund of 2010 earnings.  In the fourth quarter of 2011, OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO ordered SEET refund.  OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis.  The PUCO approved OPCo’s request to file the 2011 SEET on July 31, 2012 or one month after the PUCO issues an order on the 2010 SEET, whichever is later.  Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo.

Management is unable to predict the outcome of the unresolved 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 2016 ESP as Rejected by the PUCO

In December 2011, the PUCO approved a modified stipulation which established a new ESP that included a standard service offer (SSO) pricing for generation.  Various parties filed for rehearing with the PUCO requesting that the PUCO reconsider adoption of the modified stipulation.  In February 2012, the PUCO issued an entry on rehearing which rejected the modified stipulation and ordered a return to the 2011 ESP rates until a new rate plan is approved.

As directed by the February 2012 order, OPCo filed revised tariffs with the PUCO to implement the provisions of the 2011 ESP.  Included in the revised tariffs was the Phase-In Recovery Rider (PIRR) to recover deferred fuel costs as authorized under the 2009 – 2011 ESP order.  See the “2009 – 2011 ESP” section above.  In March 2012, the PUCO issued an order that directed OPCo to file new revised tariffs removing the PIRR and stated that its recovery would be addressed in a future proceeding.  OPCo implemented the new revised tariffs in March 2012.  In March 2012, OPCo resumed recording a weighted average cost of capital return on the PIRR deferral in accordance with the 2009 - 2011 ESP order.  Also in March 2012, OPCo filed a request for rehearing of the March 2012 order relating to the PIRR, which the PUCO denied but provided that all of the substantive concerns and issues raised would be deferred into a separate PIRR docket.  See the “Proposed June 2012 – May 2015 ESP” section below.

As a result of the PUCO’s rejection of the modified stipulation, in the first quarter of 2012, OPCo reversed a $35 million obligation to contribute to Partnership with Ohio and Ohio Growth Fund and an $8 million regulatory asset for 2011 storm damage, both originally recorded in the fourth quarter of 2011.

In March 2012, in response to OPCo’s motion for relief, the PUCO ordered that CRES providers not qualifying for the tier one capacity billing rate of $146/MW day, which is substantially below OPCo’s current capacity cost of approximately $355/MW day, will pay a tier two capacity billing rate of $255/MW day through May 2012.  The PUCO subsequently extended that order until August 8, 2012 or until an order is issued in OPCo’s pending June 2012 – May 2015 ESP proceeding, whichever is sooner.  See the “Proposed June 2012 – May 2015 ESP” section below.
 
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Proposed June 2012 – May 2015 ESP

In March 2012, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing.  The SSO rates would be effective through May 2015.  The ESP will transition OPCo to an auction-based SSO for capacity and energy by June 2015.  OPCo also filed an application with the PUCO for approval of the corporate separation of its generation assets including the transfer of generation assets to a nonregulated AEP subsidiary at net book value.  Contingent upon OPCo receiving final orders from the PUCO adopting the ESP as proposed and the corporate separation plan as filed, OPCo will conduct an energy-only auction for 5% of the SSO load with delivery beginning six months after the final orders and extending through December 2014.  In addition, a competitive bidding process would determine the price of energy for OPCo’s SSO load from January 2015 through May 2015.  The ESP proposed a two-tiered capacity pricing structure for CRES providers.  The first tier is priced at the Reliability Pricing Model (RPM) rate in effect in March 2012 of $146/MW day to serve approximately 21%, 31% and 41% of each customer class through December 2012, December 2013 and for the period January 2014 through May 2015, respectively.  All other capacity provided to CRES providers would be offered at $255/MW day.  In 2012, an additional amount of capacity may be made available at the $146/MW day rate to accommodate any community aggregation load above 21%, if applicable.

The resolution of the capacity rate is also the subject of separate proceedings before the FERC and the PUCO.  In those proceedings, OPCo is seeking a wholesale cost-based capacity rate, currently at approximately $355/MW day.  In July 2012, the PUCO issued an order in the capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer its incurred capacity costs not recovered from CRES providers to the extent that the total incurred capacity costs do not exceed $188.88/MW day.  The RPM price is approximately $20/MW day through May 2013.  The order stated that the PUCO would establish an appropriate recovery mechanism in the pending June 2012 – May 2015 ESP proceeding.  The PUCO postponed implementation of the order until August 8, 2012 or until an order is issued in OPCo’s pending June 2012 – May 2015 ESP proceeding, whichever is sooner.  In July 2012, OPCo requested rehearing of the PUCO order.  If OPCo is ultimately not permitted to fully recover its capacity cost deferral, it would reduce future net income and cash flows and impact financial condition.

The ESP also proposed to collect the PIRR from June 2013 through December 2018.  As of June 30, 2012, the net PIRR deferral was $538 million, excluding unrecognized equity carrying costs.  If OPCo is ultimately not permitted to fully recover its PIRR deferral, it would reduce future net income and cash flows and impact financial condition.

Further, the ESP proposed establishment of a non-bypassable Distribution Investment Rider through May 2015 to recover, with certain caps, post-August 2010 distribution investment.  The filing also seeks establishment of a new non-bypassable Retail Stability Rider (RSR) to recover lost generation revenues to provide financial certainty and stability during the ESP transition period.  The proposed RSR would be effective through May 2015.  Finally, the ESP proposed a storm damage recovery mechanism for the deferral of operation and maintenance costs above $5 million, effective January 2012.

Intervenors and the PUCO staff filed testimony in May 2012 in opposition to many aspects of OPCo’s ESP, including the proposed RSR and the two-tiered capacity pricing structure for CRES providers.  Intervenors recommended a flash cut to the current RPM rate for capacity.  In addition, the PUCO staff’s testimony included a proposal to increase the vegetation management base used for calculating over/under recovery on incremental vegetation spend from $21 million to $39 million, which could increase future Other Operation and Maintenance expense by $18 million on an annual basis.

Hearings on the June 2012 – May 2015 ESP were held at the PUCO during the second quarter of 2012 and oral arguments were held in July 2012.  A decision from the PUCO is expected in August 2012.
 
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2011 Ohio Distribution Base Rate Case

In February 2011, OPCo filed with the PUCO for an annual increase in distribution rates of $94 million based upon an 11.15% return on common equity to be effective January 2012.  In December 2011, a stipulation was approved by the PUCO which provided for no change in distribution rates and a new rider for a $15 million annual credit to residential ratepayers due principally to the inclusion of the rate base distribution investment in the Distribution Investment Rider (DIR) as approved by the modified stipulation in the ESP proceeding.

Because the February 2012 PUCO order rejected the ESP modified stipulation, collection of the DIR terminated.  In March 2012, OPCo filed an application with the PUCO to approve an ESP for the period June 2012 through May 2015, which includes a request for a new DIR.  See the “Proposed June 2012 – May 2015 ESP” section above.  A decision in the June 2012 – May 2015 ESP proceeding is expected in August 2012.  In March 2012, the PUCO issued an order clarifying that OPCo has the right to file a new distribution base rate case.  If OPCo is not ultimately permitted to fully recover its costs, it would reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

The PUCO selected an outside consultant to conduct an audit of OPCo’s FAC for 2009.  The outside consultant provided its audit report to the PUCO.  In January 2012, the PUCO ordered that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance.  In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges.  OPCo recorded a $30 million net favorable adjustment on the statement of income in the second quarter of 2012.  The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.  Management is unable to predict the outcome of any future consultant recommendation.  If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultants’ review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

In June 2012, OPCo filed a notice of appeal with the Supreme Court of Ohio challenging the PUCO’s decision to have proceeds from the 2008 coal contract settlement applied to OPCo’s under recovered fuel balance.  The PUCO filed a motion to dismiss OPCo’s notice of appeal at the Supreme Court of Ohio.  A decision is pending from the Supreme Court of Ohio.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its results of the 2010 and 2011 FAC audits.  The audit reports included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes.  As of June 30, 2012, the amount of OPCo’s carrying costs that could potentially be reduced due to the accumulated income tax issue is estimated to be approximately $34 million, including $18 million of unrecognized equity carrying costs.  Decisions from the PUCO are pending.  Management is unable to predict the outcome of these proceedings.  If the PUCO orders result in a reduction to the FAC deferral, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

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 filing and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio.  The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record a regulatory asset for the difference between the approved market price and the rate paid by Ormet.  Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs.  In November 2009, OPCo requested that the PUCO approve recovery of the deferral under the interim agreement plus a weighted average cost of capital carrying charge.  The deferral amount is included in OPCo’s FAC phase-in deferral balance.  In the ESP
 
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proceeding, intervenors requested that OPCo be required to refund the Ormet-related regulatory asset and requested that the PUCO prevent 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 OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.  This issue remains pending before the PUCO.  If OPCo is not ultimately permitted to fully recover its requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  Through June 30, 2012, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order.  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 these proceedings concerning the Ohio IGCC plant or what effect, if any, these proceedings would have on future net income and cash flows.  However, if OPCo is required to refund pre-construction costs collected, it could 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 scheduled to be in service in the fourth quarter of 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.8 billion, excluding AFUDC, plus an additional $120 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $120 million for transmission, excluding AFUDC.  As of June 30, 2012, excluding costs attributable to its joint owners and a $49 million provision for a Texas capital costs cap, SWEPCo has capitalized approximately $1.6 billion of expenditures, including AFUDC and capitalized interest of $269 million for generation and related transmission costs of $121 million.  As of June 30, 2012, the joint owners and SWEPCo have contractual construction obligations of approximately $65 million (including related transmission costs of $3 million).  SWEPCo’s share of the contractual construction obligations is $48 million.

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.  SWEPCo announced that it would continue construction of the Turk Plant and would not currently seek authority to serve Arkansas retail customers.  In June 2010, in response to the Arkansas Supreme Court’s decision, the APSC issued an order which reversed and set aside the previously granted CECPN.  SWEPCo currently has no contracts for the 88 MW of Turk Plant output but is evaluating its options.

The PUCT approved 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 (TIEC) filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers.  The Texas District Court and the Texas Court of Appeals affirmed the PUCT’s order in all respects.  In April 2012, SWEPCo and TIEC filed petitions for review at the Supreme Court of Texas.

If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could materially reduce future net income and cash flows and materially impact financial condition.
 
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2012 Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million based upon an 11.25% return on common equity to be effective January 2013.  The requested base rate increase includes a return on and of the Texas jurisdictional share of Turk Plant generation investment at December 2011 and total estimated transmission costs of the Turk Plant along with associated costs, including operations and maintenance costs.  It also proposed vegetation management expenditures and includes recovery of the Stall Unit.

APCo and WPCo Rate Matters

Virginia Fuel Filing

In April 2012, APCo filed an application with the Virginia SCC for an annual increase in fuel revenues of $117 million to be effective June 2012.  The filing included forecasted costs for the 15-month period ended August 2013 and requested recovery of APCo's anticipated unrecovered fuel balance as of May 2012 over a two-year period commencing in June 2012.  The non-incremental portion of APCo's forecasted and deferred wind purchased power costs were reflected in APCo's filing.  In June 2012, the Virginia SCC approved the application as filed.

Environmental Rate Adjustment Clause (RAC)

In November 2011, the Virginia SCC issued an order which approved APCo’s environmental RAC recovery of $30 million to be collected over one year beginning in February 2012 but denied recovery of certain environmental costs.  As a result, in the fourth quarter of 2011, APCo recorded a pretax write-off of $31 million on the statement of income related to environmental compliance costs incurred from January 2009 through December 2010.  In December 2011, APCo filed a notice of appeal with the Supreme Court of Virginia regarding this decision.  If the Supreme Court of Virginia were to issue a favorable decision, it could increase future net income and cash flows.

APCo’s Filings for an IGCC Plant

Through June 30, 2012, 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.  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 March 2012, West Virginia passed securitization legislation, which allows the WVPSC to establish a regulatory framework to securitize certain deferred ENEC balances and other ENEC related assets.  Also in March 2012, APCo and WPCo filed their ENEC application with the WVPSC for the fourth year of a four year phase-in plan which requested no change in ENEC rates if the WVPSC issues a financing order allowing securitization of the under-recovered ENEC deferral and other ENEC related assets.  The proposed rates consist of a Dresden Plant surcharge of $32 million and an increase in the construction surcharge of $2 million, offset by a reduction of $34 million in current ENEC rates.  APCo and WPCo anticipate filing, in the third quarter of 2012, a request for a financing order with the WVPSC pursuant to the securitization legislation.  Upon completion of the securitization, APCo and WPCo would offset the then current ENEC rates by an amount recovered through the securitization.  If the financing order is not issued, APCo and WPCo requested recovery of these costs in current rates.  As of June 30, 2012, APCo’s ENEC under-recovery balance of $326 million was recorded in Regulatory Assets on the balance sheet, excluding $6 million of unrecognized equity carrying costs.

In June 2012, a settlement agreement was filed with the WVPSC which recommended no change in total ENEC rates but reflected a $24 million increase in the construction surcharge and a $24 million decrease in ENEC rates.  The settlement agreement did not address an intervenor recommendation that the fuel cost recovery for the Mountaineer Plant be limited to the prudently incurred cost of high sulfur coal which, if approved by the WVPSC, could result in a disallowance of approximately $14 million.  Approval of the settlement agreement is pending before the WVPSC.  If the WVPSC were to disallow a portion of APCo’s and WPCo’s deferred ENEC costs, it could reduce APCo’s future net income and cash flows and impact financial condition.
 
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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 prudence 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.  In June 2012, an Administrative Law Judge issued a report that affirmed the margin sharing amount of 25% and found that the OCC does not have the jurisdiction to grant the relief sought by the OIEC regarding the comprehensive review of all affiliate fuel transactions and the ERCOT trading contracts.  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

2011 Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on common equity of 11.15%.  The $149 million net annual increase reflects an increase in base rates of $178 million offset by proposed corresponding reductions of $13 million to the off-system sales sharing rider, $9 million to the PJM cost rider and $7 million to the clean coal technology rider rates.  The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.

In May 2012, the Indiana Office of Utility Consumer Counselor filed testimony that recommended an increase in base rates of $28 million, excluding reductions to certain riders, based upon a return on common equity of 9.2%.  I&M filed rebuttal testimony in May 2012 which supported an increase of $170 million in base rates, excluding reductions to certain riders.  Final hearings were held in June 2012.  A decision from the IURC is expected in the fourth quarter of 2012.

Life Cycle Management Project

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects for Cook Plant Units 1 and 2.  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.

In Indiana, I&M requested recovery of certain project costs, including interest, through a rider effective January 2013.  In Michigan, I&M requested that the MPSC approve a Certificate of Public Convenience and Necessity and authorize I&M to defer, on an interim basis, incremental depreciation and property tax costs, including interest, along with study, analysis and development costs until the applicable costs are included in I&M’s base rates.  As of June 30, 2012, I&M has incurred $92 million related to the LCM Project.  If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.
 
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KPCo Rate Matters

Big Sandy Unit 2 FGD System

In May 2012, KPCo filed a motion with the KPSC to withdraw its application seeking approval of a Certificate of Public Convenience and Necessity to retrofit Big Sandy Unit 2 with a dry FGD system.  The motion was accepted by the KPSC in May 2012.  KPCo is currently re-evaluating its needs to meet the short and long-term energy needs of its customers at the most reasonable costs.  KPCo has not determined its future plan.  As of June 30, 2012, KPCo has incurred $29 million related to the project.  Management intends to pursue recovery of all costs related to this project.  If KPCo is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.
 
FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund

In 2004, AEP eliminated transaction-based through-and-out transmission service charges and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA through March 2006.  Intervenors objected and 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.  In 2006, a FERC Administrative Law Judge 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.

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 supported AEP’s position and required a compliance filing.  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 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 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

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC.  It is unknown at this time whether the Interconnection Agreement 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.  Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future.  If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement 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.
 
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3.  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 effect on our financial statements.  The Commitments, Guarantees and Contingencies note within our 2011 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 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 credit facilities totaling $3.25 billion, under which we may issue up to $1.35 billion as letters of credit.  As of June 30, 2012, the maximum future payments for letters of credit issued under the credit facilities were $167 million with maturities ranging from July 2012 to June 2013.

We have $402 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $407 million.  The letters of credit have maturities ranging from March 2013 to July 2014.

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 $115 million.  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.  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, 2012, SWEPCo has collected approximately $56 million through a rider for final mine closure and reclamation costs, of which $11 million is recorded in Other Current Liabilities, $3 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $42 million is recorded in Asset Retirement Obligations on our condensed 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 2011 Annual Report “Dispositions” section of Note 6.  As of June 30, 2012, there were no material liabilities recorded for any indemnifications.
 
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Master Lease Agreements

We lease certain equipment under master lease agreements.  Under the 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.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.  As of June 30, 2012, the maximum potential loss for these lease agreements was approximately $17 million assuming the fair value of the equipment is zero at the end of the lease term.

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 $15 million and $17 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2012.

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.  The maximum potential losses related to the guarantee are approximately $12 million and $13 million for I&M and SWEPCo, respectively, 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 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.  The court ordered all defendants to respond to the refiled complaints in October 2011.  In March 2012, the court granted the defendants’ motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations.  Plaintiffs appealed the decision to the Fifth Circuit Court of Appeals.  We will continue to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

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
 
51
 
$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.  The court heard oral argument in November 2011.  We believe the action is without merit and will continue 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 $10 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.

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 cost approximately $400 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.  Due to the extensive lead time required to manufacture and install new turbine rotors, I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The installation of the new turbine rotors and other equipment occurred as planned during the fall 2011 refueling outage of Unit 1.

I&M maintains insurance through NEIL.  As of June 30, 2012, we recorded $64 million in Prepayments and Other Current Assets on our condensed balance sheets representing amounts under NEIL insurance policies.  Through June 30, 2012, I&M received payments from NEIL of $203 million for the cost incurred to date to repair the property damage and $185 million under an accidental outage policy.
 
52
 
The claims process with NEIL continues and includes a review of claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies, 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.  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 reduce future net income and cash flows and impact financial condition.

OPERATIONAL CONTINGENCIES

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) was among the companies named as defendants in some of these cases.  We settled, received summary judgment or were dismissed from all of these cases.  The plaintiffs appealed the dismissal of several cases involving AEP companies in Nevada to the Ninth Circuit Court of Appeals.  We will continue to defend the cases on appeal.  We believe the provision we have is adequate.  We believe the remaining exposure is immaterial.

4.  ACQUISITION

2012

BlueStar Energy (Generation and Marketing segment)

In March 2012, we completed the acquisition of BlueStar Energy Holdings, Inc. (BlueStar) and its independent retail electric supplier BlueStar Energy Solutions for $70 million, subject to working capital adjustments.  This transaction also included goodwill of $14 million, intangible assets associated with sales contracts and customer accounts of $59 million and liabilities associated with supply contracts of $25 million.  These amounts are subject to revision once further evaluations are complete.  BlueStar has been in operation since 2002.  Beginning in June 2012, BlueStar began doing business as AEP Energy.  AEP Energy provides electric supply for retail customers in Ohio, Illinois and other deregulated electricity markets and also provides energy solutions throughout the United States, including demand response and energy efficiency services.
 
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5.  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, 2012 and 2011:

     
Other Postretirement
  
 
Pension Plans
  
Benefit Plans
  
 
Three Months Ended June 30,
  
Three Months Ended June 30,
  
 
2012
  
2011
  
2012
  
2011
  
 
(in millions)
  
Service Cost
   $ 19     $ 18     $ 11     $ 10  
Interest Cost
     55       60       26       27  
Expected Return on Plan Assets
     (79 )     (78 )     (25 )     (27 )
Amortization of Prior Service Credit
     -       -       (4 )     -  
Amortization of Net Actuarial Loss
     38       31       15       8  
Net Periodic Benefit Cost
   $ 33     $ 31     $ 23     $ 18  

     
Other Postretirement
  
 
Pension Plans
  
Benefit Plans
  
 
Six Months Ended June 30,
  
Six Months Ended June 30,
  
 
2012
  
2011
  
2012
  
2011
  
 
(in millions)
  
Service Cost
   $ 38     $ 36     $ 23     $ 21  
Interest Cost
     111       119       52       54  
Expected Return on Plan Assets
     (159 )     (157 )     (50 )     (54 )
Amortization of Prior Service Credit
     -       -       (9 )     -  
Amortization of Net Actuarial Loss
     75       61       29       15  
Net Periodic Benefit Cost
   $ 65     $ 59     $ 45     $ 36  

 
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6.  BUSINESS SEGMENTS

As outlined in our 2011 Annual Report, our primary business is the generation, transmission and distribution of electricity.  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.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

While our Utility Operations segment remains our primary business segment, the advancement of an area of our business prompted us to identify a new reportable segment.  Starting in the fourth quarter of 2011, we established our new Transmission Operations segment as described below:

Utility Operations

·  
Generation of electricity for sale to U.S. retail and wholesale customers.
·  
Transmission and distribution of electricity through assets owned and operated by our ten utility operating companies.

Transmission Operations

·  
Development, construction and operation of transmission facilities through investments in our wholly-owned transmission subsidiaries that were established in 2009 and our transmission joint ventures.  These investments have PUCT-approved or FERC-approved returns on equity.

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

·  
Nonregulated generation in ERCOT.
·  
Marketing, risk management and retail activities in ERCOT, PJM and MISO.

The remainder of our activities is presented as All Other.  While not considered a reportable 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 were financial derivatives which settled and expired in the fourth quarter of 2011.
·  
Revenue sharing related to the Plaquemine Cogeneration Facility which ended in the fourth quarter of 2011.

 
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The tables below present our reportable segment information for the three and six months ended June 30, 2012 and 2011 and balance sheet information as of June 30, 2012 and December 31, 2011.  These amounts include certain estimates and allocations where necessary.  We reclassified prior year amounts to conform to the current year’s presentation.

               
Nonutility Operations
                  
                     
Generation
                  
 
Utility
  
Transmission
  
AEP River
  
and
  
All Other
  
Reconciling
      
 
Operations
  
Operations
  
Operations
  
Marketing
  
(a)
  
 Adjustments
  
Consolidated
   
(in millions)
Three Months Ended June 30, 2012
                                          
Revenues from:
                                          
External Customers
  
$
 3,234 
  
$
 1 
  
$
 163 
  
$
 148 
  
$
 5 
  
$
 - 
  
$
 3,551 
Other Operating Segments
    
 24 
    
 1 
    
 4 
    
 - 
    
 1 
    
 (30)
    
 - 
Total Revenues
  
$
 3,258 
  
$
 2 
  
$
 167 
  
$
 148 
  
$
 6 
  
$
 (30)
  
$
 3,551 
                                           
Net Income (Loss)
  
$
 365 
  
$
 8 
  
$
 3 
  
$
 (5)
  
$
 (8)
  
$
 - 
  
$
 363 
                                           
               
Nonutility Operations
                  
                     
Generation
                  
 
Utility
  
Transmission
  
AEP River
  
and
  
All Other
  
Reconciling
      
 
Operations
  
Operations
  
Operations
  
Marketing
  
(a)
  
 Adjustments
  
Consolidated
   
(in millions)
Three Months Ended June 30, 2011
                                          
Revenues from:
                                          
External Customers
  
$
 3,359 
  
$
 1 
  
$
 162 
  
$
 79 
  
$
 8 
  
$
 - 
  
$
 3,609 
Other Operating Segments
    
 29 
    
 (1)
    
 4 
    
 - 
    
 2 
    
 (34)
    
 - 
Total Revenues
  
$
 3,388 
  
$
 - 
  
$
 166 
  
$
 79 
  
$
 10 
  
$
 (34)
  
$
 3,609 
                                           
Net Income (Loss)
  
$
 350 
  
$
 6 
  
$
 (1)
  
$
 11 
  
$
 (13)
  
$
 - 
  
$
 353 

               
Nonutility Operations
                  
                     
Generation
                  
 
Utility
  
Transmission
AEP River
  
and
  
All Other
  
Reconciling
      
 
Operations
  
Operations
Operations
  
Marketing
  
(a)
  
 Adjustments
  
Consolidated
   
(in millions)
Six Months Ended June 30, 2012
                                          
Revenues from:
                                          
External Customers
  
$
 6,596 
  
$
 2 
  
$
 335 
  
$
 233 
  
$
 10 
  
$
 - 
  
$
 7,176 
Other Operating Segments
    
 47 
    
 3 
    
 11 
    
 - 
    
 3 
    
 (64)
    
 - 
Total Revenues
  
$
 6,643 
  
$
 5 
  
$
 346 
  
$
 233 
  
$
 13 
  
$
 (64)
  
$
 7,176 
                                           
Net Income (Loss)
  
$
 749 
  
$
 17 
  
$
 12 
  
$
 (6)
  
$
 (19)
  
$
 - 
  
$
 753 
                                           
               
Nonutility Operations
                  
                     
Generation
                  
 
Utility
  
Transmission
AEP River
  
and
  
All Other
  
Reconciling
      
 
Operations
  
Operations
Operations
  
Marketing
  
(a)
  
 Adjustments
  
Consolidated
   
(in millions)
Six Months Ended June 30, 2011
                                          
Revenues from:
                                          
External Customers
  
$
 6,856 
  
$
 1 
  
$
 329 
  
$
 141 
  
$
 12 
  
$
 - 
  
$
 7,339 
Other Operating Segments
    
 56 
    
 (1)
    
 9 
    
 1 
    
 3 
    
 (68)
    
 - 
Total Revenues
  
$
 6,912 
  
$
 - 
  
$
 338 
  
$
 142 
  
$
 15 
  
$
 (68)
  
$
 7,339 
                                           
Net Income (Loss)
  
$
 724 
  
$
 10 
  
$
 6 
  
$
 12 
  
$
 (44)
  
$
 - 
  
$
 708 

 
56
 
               
Nonutility Operations
                  
                     
Generation
        
Reconciling
      
 
Utility
  
Transmission
  
AEP River
  
and
  
All Other
  
 Adjustments
      
 
Operations
  
Operations
  
Operations
  
Marketing
  
(a)
  
(b)
  
Consolidated
   
(in millions)
June 30, 2012
                                          
Total Property, Plant and Equipment
  
$
 55,289 
  
$
 508 
  
$
 624 
  
$
 618 
  
$
 11 
  
$
 (266)
  
$
 56,784 
Accumulated Depreciation and
                                          
Amortization
    
 18,627 
    
 2 
    
 150 
    
 232 
    
 10 
    
 (65)
    
 18,956 
Total Property, Plant and
                                          
 Equipment - Net
  
$
 36,662 
  
$
 506 
  
$
 474 
  
$
 386 
  
$
 1 
  
$
 (201)
  
$
 37,828 
                                           
Total Assets
  
$
 50,983 
  
$
 865 
  
$
 650 
  
$
 1,030 
  
$
 16,638 
  
$
 (16,745)
(c)
$
 53,421 
                                           
               
Nonutility Operations
                  
                     
Generation
        
Reconciling
      
 
Utility
  
Transmission
  
AEP River
  
and
  
All Other
  
 Adjustments
      
 
Operations
  
Operations
  
Operations
  
Marketing
  
(a)
  
(b)
  
Consolidated
   
(in millions)
December 31, 2011
                                          
Total Property, Plant and Equipment
  
$
 54,396 
  
$
 323 
  
$
 608 
  
$
 590 
  
$
 11 
  
$
 (258)
  
$
 55,670 
Accumulated Depreciation and
                                          
 Amortization
    
 18,393 
    
 - 
    
 136 
    
 219 
    
 10 
    
 (59)
    
 18,699 
Total Property, Plant and
                                          
 Equipment - Net
  
$
 36,003 
  
$
 323 
  
$
 472 
  
$
 371 
  
$
 1 
  
$
 (199)
  
$
 36,971 
                                           
Total Assets
  
$
 50,093 
  
$
 594 
  
$
 659 
  
$
 868 
  
$
 16,751 
  
$
 (16,742)
(c)
$
 52,223 

(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 were financial derivatives which settled and expired in the fourth quarter of 2011.
·  
Revenue sharing related to the Plaquemine Cogeneration Facility which ended 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.

7.  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.
 
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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, 2012 and December 31, 2011:

Notional Volume of Derivative Instruments
               
 
Volume
    
 
June 30,
  
December 31,
  
Unit of
 
2012
  
2011
  
Measure
Primary Risk Exposure
(in millions)
    
Commodity:
              
Power
     704       609  
MWHs
Coal
     16       21  
Tons
Natural Gas
     115       100  
MMBtus
Heating Oil and Gasoline
     4       6  
Gallons
Interest Rate
   $ 296     $ 226  
USD
                   
Interest Rate and Foreign Currency
   $ 803     $ 907  
USD

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 activities as “Commodity.”  We do not hedge all fuel price risk.
 
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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 future borrowings of fixed-rate debt.  Our forecasted 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 on the condensed balance sheets 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, 2012 and December 31, 2011 balance sheets, we netted $18 million and $26 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $94 million and $133 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.
 
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The following tables represent the gross fair value impact of our derivative activity on our condensed balance sheets as of June 30, 2012 and December 31, 2011:

Fair Value of Derivative Instruments
  
June 30, 2012
  
   
   
Risk Management
                    
   
Contracts
  
Hedging Contracts
            
           
Interest Rate
            
           
and Foreign
            
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Other (b)
    
Total
  
   
(in millions)
  
Current Risk Management Assets
   $ 996   $ 37   $ 1   $ (815 )   $ 219  
Long-term Risk Management Assets
     733     15     1     (310 )     439  
Total Assets
     1,729     52     2     (1,125 )     658  
                                   
Current Risk Management Liabilities
     951     53     33     (872 )     165  
Long-term Risk Management Liabilities
     586     21     2     (350 )     259  
Total Liabilities
     1,537     74     35     (1,222 )     424  
                                   
Total MTM Derivative Contract Net Assets
                                  
(Liabilities)
   $ 192   $ (22 ) $ (33 ) $ 97     $ 234  
 
Fair Value of Derivative Instruments
  
December 31, 2011
  
   
   
Risk Management
                            
   
Contracts
  
Hedging Contracts
                
               
Interest Rate
                
               
and Foreign
                
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Other (b)
    
Total
  
   
(in millions)
  
Current Risk Management Assets
   $ 852   $ 24   $ -   $ (683 )   $ 193  
Long-term Risk Management Assets
     641     15     -     (253 )     403  
Total Assets
     1,493     39     -     (936 )     596  
                                   
Current Risk Management Liabilities
     847     29     20     (746 )     150  
Long-term Risk Management Liabilities
     483     15     22     (325 )     195  
Total Liabilities
     1,330     44     42     (1,071 )     345  
                                   
Total MTM Derivative Contract Net Assets
                                  
(Liabilities)
   $ 163   $ (5 ) $ (42 ) $ 135     $ 251  

 
(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 de-designated risk management contracts.
 
 
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The tables below present our activity of derivative risk management contracts for the three and six months ended June 30, 2012 and 2011:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2012 and 2011
         
Location of Gain (Loss)
  
2012 
  
2011 
   
(in millions)
Utility Operations Revenues
  
$
 4 
  
$
 18 
Other Revenues
    
 5 
    
 13 
Regulatory Assets (a)
    
 (17)
    
 (5)
Regulatory Liabilities (a)
    
 13 
    
 5 
Total Gain (Loss) on Risk Management Contracts
  
$
 5 
  
$
 31 
             
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Six Months Ended June 30, 2012 and 2011
         
Location of Gain (Loss)
  
2012 
  
2011 
   
(in millions)
Utility Operations Revenues
  
$
 14 
  
$
 38 
Other Revenues
    
 8 
    
 15 
Regulatory Assets (a)
    
 (38)
    
 (1)
Regulatory Liabilities (a)
    
 27 
    
 11 
Total Gain (Loss) on Risk Management Contracts
  
$
 11 
  
$
 63 

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

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.

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 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 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.”
 
61
 
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.

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 statements of income.  During the three and six months ended June 30, 2012, we recognized gains of $1 million and $2 million, respectively, on our hedging instruments and offsetting losses of $1 million and $2 million, respectively, on our long-term debt.  During the three and six months ended June 30, 2011, we recognized gains of $4 million and $8 million, respectively, on our hedging instruments and offsetting losses of $5 million and $9 million, respectively, on our long-term debt.   During the three and six months ended June 30, 2012 and 2011, hedge ineffectiveness was immaterial.

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 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 and natural gas 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 statements of income, or in Regulatory Assets or Regulatory Liabilities on our condensed balance sheets, depending on the specific nature of the risk being hedged.  During the three and six months ended June 30, 2012 and 2011, we designated power, coal and natural gas derivatives as cash flow hedges.

We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our condensed statements of income.  During the three and six months ended June 30, 2012 and 2011, 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) on our condensed balance sheets into Interest Expense on our condensed statements of income in those periods in which hedged interest payments occur.  During the three and six months ended June 30, 2012 and 2011, 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 balance sheets into Depreciation and Amortization expense on our condensed 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, 2012 and 2011, we designated foreign currency derivatives as cash flow hedges.

During the three and six months ended June 30, 2012 and 2011, hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies disclosed above.
 
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The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2012 and 2011.  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, 2012
  
     
Interest Rate
      
     
and Foreign
      
 
Commodity
  
Currency
  
Total
  
 
(in millions)
  
Balance in AOCI as of March 31, 2012
 $ (16 ) $ (18 ) $ (34 )
Changes in Fair Value Recognized in AOCI
   (3 )   (13 )   (16 )
Amount of (Gain) or Loss Reclassified from AOCI
                  
to Statement of Income/within Balance Sheet:
                  
Utility Operations Revenues
   -     -     -  
Other Revenues
   (2 )   -     (2 )
Purchased Electricity for Resale
   6     -     6  
Interest Expense
   -     1     1  
Regulatory Assets (a)
   1     -     1  
Regulatory Liabilities (a)
   -     -     -  
Balance in AOCI as of June 30, 2012
 $ (14 ) $ (30 ) $ (44 )
 
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 Statement of Income/within Balance Sheet:
                  
Utility Operations Revenues
   2     -     2  
Other Revenues
   (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  

 
63
 
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
  
For the Six Months Ended June 30, 2012
  
     
Interest Rate
      
     
and Foreign
      
 
Commodity
  
Currency
  
Total
  
 
(in millions)
  
Balance in AOCI as of December 31, 2011
 $ (3 ) $ (20 ) $ (23 )
Changes in Fair Value Recognized in AOCI
   (23 )   (12 )   (35 )
Amount of (Gain) or Loss Reclassified from AOCI
                  
to Statement of Income/within Balance Sheet:
                  
Utility Operations Revenues
   -     -     -  
Other Revenues
   (3 )   -     (3 )
Purchased Electricity for Resale
   13     -     13  
Interest Expense
   -     2     2  
Regulatory Assets (a)
   2     -     2  
Regulatory Liabilities (a)
   -     -     -  
Balance in AOCI as of June 30, 2012
 $ (14 ) $ (30 ) $ (44 )
 
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 Statement of Income/within Balance Sheet:
                  
Utility Operations Revenues
   2     -     2  
Other Revenues
   (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  

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

 
64
 
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of June 30, 2012 and December 31, 2011 were:

Impact of Cash Flow Hedges on the Condensed Balance Sheet
  
June 30, 2012
  
             
     
Interest Rate
      
     
and Foreign
      
 
Commodity
  
Currency
  
Total
  
 
(in millions)
  
Hedging Assets (a)
 $ 38   $ -   $ 38  
Hedging Liabilities (a)
   60     35     95  
AOCI Gain (Loss) Net of Tax
   (14 )   (30 )   (44 )
Portion Expected to be Reclassified to Net
                  
Income During the Next Twelve Months
   (10 )   (3 )   (13 )
 
Impact of Cash Flow Hedges on the Condensed Balance Sheet
  
December 31, 2011
  
             
     
Interest Rate
      
     
and Foreign
      
 
Commodity
  
Currency
  
Total
  
 
(in millions)
  
Hedging Assets (a)
 $ 20   $ -   $ 20  
Hedging Liabilities (a)
   25     42     67  
AOCI Gain (Loss) Net of Tax
   (3 )   (20 )   (23 )
Portion Expected to be Reclassified to Net
                  
Income During the Next Twelve Months
   (3 )   (2 )   (5 )

(a)
Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed 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, 2012, 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 39 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.  AEP and its subsidiaries have not experienced 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, 2012 and December 31, 2011:

 
June 30,
  
December 31,
  
 
2012
  
2011
  
 
(in millions)
  
Liabilities for Derivative Contracts with Credit Downgrade Triggers
   $ 7     $ 32  
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post
     35       39  
Amount Attributable to RTO and ISO Activities
     33       38  

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.  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, 2012 and December 31, 2011:

 
June 30,
  
December 31,
  
 
2012
  
2011
  
 
(in millions)
  
Liabilities for Contracts with Cross Default Provisions Prior to ContractualNetting Arrangements
   $ 658     $ 515  
Amount of Cash Collateral Posted
     10       56  
Additional Settlement Liability if Cross Default Provision is Triggered
     375       291  

8.  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.
 
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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.  The main driver of our contracts being classified as Level 3 is the inability to substantiate our energy price curves in the market.   To a lesser extent, these contracts could be sensitive to volumetric estimates for some structured transactions.  However, a significant portion of our Level 3 volumetric contractual positions have been economically hedged which greatly limits potential earnings volatility.

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.  Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds.  Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  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.

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 classified as Level 2 measurement inputs.  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.

The book values and fair values of Long-term Debt as of June 30, 2012 and December 31, 2011 are summarized in the following table:

   
June 30, 2012
    
December 31, 2011
  
   
Book Value
    
Fair Value
    
Book Value
    
Fair Value
  
   
(in millions)
  
Long-term Debt
   $ 17,302     $ 20,025     $ 16,516     $ 19,259  

 
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Fair Value Measurements of Other Temporary Investments

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

The following is a summary of Other Temporary Investments:

       
June 30, 2012
  
           
Gross
  
Gross
  
Estimated
  
           
 Unrealized
  
Unrealized
  
 Fair
Other Temporary Investments
  
Cost
  
Gains
  
Losses
  
Value
       
(in millions)
  
Restricted Cash (a)
  
$
 217 
  
$
 - 
  
$
 - 
  
$
 217 
  
Fixed Income Securities:
                          
 
Mutual Funds
    
 64 
    
 1 
    
 - 
    
 65 
  
Equity Securities - Mutual Funds
    
 11 
    
 4 
    
 - 
    
 15 
  
Total Other Temporary Investments
  
$
 292 
  
$
 5 
  
$
 - 
  
$
 297 
  
                               
       
December 31, 2011
  
           
Gross
  
Gross
  
Estimated
  
           
 Unrealized
  
Unrealized
  
 Fair
  
Other Temporary Investments
  
Cost
  
Gains
  
Losses
  
Value
  
       
(in millions)
  
Restricted Cash (a)
  
$
 216 
  
$
 - 
  
$
 - 
  
$
 216 
  
Fixed Income Securities:
                          
 
Mutual Funds
    
 64 
    
 - 
    
 - 
    
 64 
  
Equity Securities - Mutual Funds
    
 11 
    
 3 
    
 - 
    
 14 
  
Total Other Temporary Investments
  
$
 291 
  
$
 3 
  
$
 - 
  
$
 294 
  
                               
(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, 2012 and 2011:

 
Three Months Ended June 30,
  
Six Months Ended June 30,
 
2012
  
2011
  
2012
  
2011
 
(in millions)
Proceeds from Investment Sales
   $ -     $ 51     $ -     $ 247
Purchases of Investments
     1       5       1       153
Gross Realized Gains on Investment Sales
     -       -       -       -
Gross Realized Losses on Investment Sales
     -       -       -       -

As of June 30, 2012 and December 31, 2011, we had no Other Temporary Investments with an unrealized loss position.  As of June 30, 2012, fixed income securities are primarily debt based mutual funds with short and intermediate maturities.  Mutual funds may be sold and do not contain maturity dates.

 
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The following tables provide details of Other Temporary Investments included in Accumulated Other Comprehensive Income (Loss) on our balance sheet and the reasons for changes for the three and six months ended June 30, 2012.  All amounts in the following table are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Other Temporary Investments
  
Three Months Ended June 30, 2012
  
       
 
(in millions)
  
Balance in AOCI as of March 31, 2012
   $ 4  
Changes in Fair Value Recognized in AOCI
     (1 )
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income:
        
Interest Income
     -  
Balance in AOCI as of June 30, 2012
   $ 3  

Total Accumulated Other Comprehensive Income (Loss) Activity for Other Temporary Investments
  
Six Months Ended June 30, 2012
  
       
 
(in millions)
  
Balance in AOCI as of December 31, 2011
   $ 2  
Changes in Fair Value Recognized in AOCI
     1  
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income:
        
Interest Income
     -  
Balance in AOCI as of June 30, 2012
   $ 3  

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.
 
69
 
The following is a summary of nuclear trust fund investments as of June 30, 2012 and December 31, 2011:

     
June 30, 2012
  
December 31, 2011
     
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
  
$
 16 
  
$
 - 
  
$
 - 
  
$
 18 
  
$
 - 
  
$
 - 
Fixed Income Securities:
                                    
 
United States Government
    
 644 
    
 104 
    
 (1)
    
 544 
    
 61 
    
 (1)
 
Corporate Debt
    
 44 
    
 5 
    
 (1)
    
 54 
    
 5 
    
 (2)
 
State and Local Government
    
 256 
    
 1 
    
 (1)
    
 330 
    
 - 
    
 (2)
 
  Subtotal Fixed Income Securities
  
 944 
    
 110 
    
 (3)
    
 928 
    
 66 
    
 (5)
Equity Securities - Domestic
    
 698 
    
 258 
    
 (79)
    
 646 
    
 215 
    
 (80)
Spent Nuclear Fuel and
                                    
 
Decommissioning Trusts
  
$
 1,658 
  
$
 368 
  
$
 (82)
  
$
 1,592 
  
$
 281 
  
$
 (85)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2012 and 2011:

 
Three Months Ended June 30,
  
Six Months Ended June 30,
 
2012
  
2011
  
2012
  
2011
 
(in millions)
Proceeds from Investment Sales
 $ 183   $ 177   $ 517   $ 465
Purchases of Investments
   192     186     545     492
Gross Realized Gains on Investment Sales
   3     7     5     12
Gross Realized Losses on Investment Sales
   1     4     2     9

The adjusted cost of debt securities was $834 million and $862 million as of June 30, 2012 and December 31, 2011, respectively.  The adjusted cost of equity securities was $440 million and $431 million as of June 30, 2012 and December 31, 2011, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2012 was as follows:

 
Fair Value
  
 
of Debt
  
 
Securities
  
 
(in millions)
  
Within 1 year
   $ 40  
1 year – 5 years
     362  
5 years – 10 years
     315  
After 10 years
     227  
Total
   $ 944  

 
70
 
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, 2012 and December 31, 2011.  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, 2012
  
                               
   
Level 1
    
Level 2
    
Level 3
    
Other
    
Total
  
                               
Assets:
  
(in millions)
  
                               
Cash and Cash Equivalents (a)
   $ 20     $ -     $ -     $ 277     $ 297  
                                         
Other Temporary Investments
                                        
Restricted Cash (a)
     186       -       -       31       217  
Fixed Income Securities:
                                        
Mutual Funds
     65       -       -       -       65  
Equity Securities - Mutual Funds (b)
     15       -       -       -       15  
Total Other Temporary Investments
     266       -       -       31       297  
                                         
Risk Management Assets
                                        
Risk Management Commodity Contracts (c) (f)
     53       1,509       163       (1,128 )     597  
Cash Flow Hedges:
                                        
Commodity Hedges (c)
     13       38       1       (14 )     38  
Fair Value Hedges
     -       2       -       -       2  
De-designated Risk Management Contracts (d)
     -       -       -       21       21  
Total Risk Management Assets
     66       1,549       164       (1,121 )     658  
                                         
Spent Nuclear Fuel and Decommissioning Trusts
                                        
Cash and Cash Equivalents (e)
     -       4       -       12       16  
Fixed Income Securities:
                                        
United States Government
     -       644       -       -       644  
Corporate Debt
     -       44       -       -       44  
State and Local Government
     -       256       -       -       256  
Subtotal Fixed Income Securities
     -       944       -       -       944  
Equity Securities - Domestic (b)
     698       -       -       -       698  
Total Spent Nuclear Fuel and Decommissioning Trusts
     698       948       -       12       1,658  
                                         
Total Assets
   $ 1,050     $ 2,497     $ 164     $ (801 )   $ 2,910  
                                         
Liabilities:
                                        
                                         
Risk Management Liabilities
                                        
Risk Management Commodity Contracts (c) (f)
   $ 47     $ 1,419     $ 67     $ (1,204 )   $ 329  
Cash Flow Hedges:
                                        
Commodity Hedges (c)
     -       74       -       (14 )     60  
Interest Rate/Foreign Currency Hedges
     -       35       -       -       35  
Total Risk Management Liabilities
   $ 47     $ 1,528     $ 67     $ (1,218 )   $ 424  

 
71
 

Assets and Liabilities Measured at Fair Value on a Recurring Basis
  
December 31, 2011
  
                               
   
Level 1
    
Level 2
    
Level 3
    
Other
    
Total
  
                               
Assets:
  
(in millions)
  
                               
Cash and Cash Equivalents (a)
   $ 6     $ -     $ -     $ 215     $ 221  
                                         
Other Temporary Investments
                                        
Restricted Cash (a)
     191       -       -       25       216  
Fixed Income Securities:
                                        
Mutual Funds
     64       -       -       -       64  
Equity Securities - Mutual Funds (b)
     14       -       -       -       14  
Total Other Temporary Investments
     269       -       -       25       294  
                                         
Risk Management Assets
                                        
Risk Management Commodity Contracts (c) (g)
     47       1,299       147       (945 )     548  
Cash Flow Hedges:
                                        
Commodity Hedges (c)
     15       23       -       (18 )     20  
De-designated Risk Management Contracts (d)
     -       -       -       28       28  
Total Risk Management Assets
     62       1,322       147       (935 )     596  
                                         
Spent Nuclear Fuel and Decommissioning Trusts
                                        
Cash and Cash Equivalents (e)
     -       5       -       13       18  
Fixed Income Securities:
                                        
United States Government
     -       544       -       -       544  
Corporate Debt
     -       54       -       -       54  
State and Local Government
     -       330       -       -       330  
Subtotal Fixed Income Securities
     -       928       -       -       928  
Equity Securities - Domestic (b)
     646       -       -       -       646  
Total Spent Nuclear Fuel and Decommissioning Trusts
     646       933       -       13       1,592  
                                         
Total Assets
   $ 983     $ 2,255     $ 147     $ (682 )   $ 2,703  
                                         
Liabilities:
                                        
                                         
Risk Management Liabilities
                                        
Risk Management Commodity Contracts (c) (g)
   $ 43     $ 1,209     $ 78     $ (1,052 )   $ 278  
Cash Flow Hedges:
                                        
Commodity Hedges (c)
     -       43       -       (18 )     25  
Interest Rate/Foreign Currency Hedges
     -       42       -       -       42  
Total Risk Management Liabilities
   $ 43     $ 1,294     $ 78     $ (1,070 )   $ 345  

(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.
(f)
The June 30, 2012 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 2012, $12 million in periods 2013-2015 and ($8) million in periods 2016-2018;  Level 2 matures $12 million in 2012, $52 million in periods 2013-2015, $17 million in periods 2016-2017 and $9 million in periods 2018-2030;  Level 3 matures $7 million in 2012, $38 million in periods 2013-2015, $24 million in periods 2016-2017 and $27 million in periods 2018-2030.  Risk management commodity contracts are substantially comprised of power contracts.
(g)
The December 31, 2011 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $3 million in 2012, $7 million in periods 2013-2015 and ($6) million in periods 2016-2018;  Level 2 matures $21 million in 2012, $50 million in periods 2013-2015, $11 million in periods 2016-2017 and $8 million in periods 2018-2030;  Level 3 matures ($19) million in 2012, $44 million in periods 2013-2015, $18 million in periods 2016-2017 and $26 million in periods 2018-2030.  Risk management commodity contracts are substantially comprised of power contracts.

There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2012 and 2011.
 
72
 
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, 2012
  
Assets (Liabilities)
  
   
(in millions)
  
Balance as of March 31, 2012
   $ 92  
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
     (11 )
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
        
Relating to Assets Still Held at the Reporting Date (a)
     4  
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
     -  
Purchases, Issuances and Settlements (c)
     15  
Transfers into Level 3 (d) (f)
     (1 )
Transfers out of Level 3 (e) (f)
     (8 )
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
     6  
Balance as of June 30, 2012
   $ 97  

   
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  

 
73
 
   
Net Risk Management
  
Six Months Ended June 30, 2012
  
Assets (Liabilities)
  
   
(in millions)
  
Balance as of December 31, 2011
   $ 69  
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
     (17 )
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
        
Relating to Assets Still Held at the Reporting Date (a)
     5  
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
     -  
Purchases, Issuances and Settlements (c)
     33  
Transfers into Level 3 (d) (f)
     14  
Transfers out of Level 3 (e) (f)
     (20 )
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
     13  
Balance as of June 30, 2012
   $ 97  

   
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  

(a)
Included in revenues on our 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 our condensed statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets.

The following table quantifies the significant unobservable inputs used in developing the fair value of our Level 3 positions as of June 30, 2012:

     
Fair Value
  
Valuation
  
Significant
  
Forward Price Range
   
Assets
  
Liabilities
Technique
Unobservable Input (a)
  
Low
  
High
     
(in millions)
                    
 
Energy Contracts
  
$
 152 
  
$
 60 
  
Discounted Cash Flow
  
Forward Market Price
  
$
 10.76 
  
$
 174.18 
 
FTRs
    
 12 
    
 7 
  
Discounted Cash Flow
  
Forward Market Price
    
 (10.77)
    
 10.78 
 
Total
  
$
 164 
  
$
 67 
                    

 
(a)
Represents market prices beyond defined terms for Levels 1 and 2.

 
74
 
9.  INCOME TAXES

AEP System Tax Allocation Agreement

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.

Federal and State Income Tax Audit Status

We are no longer subject to U.S. federal examination for years before 2009.  We completed the examination of the years 2007 and 2008 in April 2011 and settled all outstanding issues on appeal for the years 2001 through 2006 in October 2011.  The settlements did not have a material impact on net income, cash flows or financial condition.  The IRS examination of years 2009 and 2010 started in October 2011.  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 impact 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.  In March 2012, AEP settled all outstanding franchise tax issues with the state of Ohio for the years 2000 through 2009.  The settlements did not have a material impact on net income, cash flows or financial condition.

10.  FINANCING ACTIVITIES
 
Long-term Debt
 
Type of Debt
  
June 30, 2012
    
December 31, 2011
  
   
(in millions)
  
Senior Unsecured Notes
   $ 11,858     $ 11,737  
Pollution Control Bonds
     1,958       2,112  
Notes Payable
     497       402  
Securitization Bonds
     2,389       1,688  
Junior Subordinated Debentures
     315       315  
Spent Nuclear Fuel Obligation (a)
     265       265  
Other Long-term Debt
     51       29  
Fair Value of Interest Rate Hedges
     6       7  
Unamortized Discount, Net
     (37 )     (39 )
Total Long-term Debt Outstanding
     17,302       16,516  
Long-term Debt Due Within One Year
     1,983       1,433  
Long-term Debt
   $ 15,319     $ 15,083  

(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 $308 million at both June 30, 2012 and December 31, 2011 and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets.

 
75
 
Long-term debt and other securities issued, retired and principal payments made during the first six months of 2012 are shown in the tables below:

       
Principal
  
Interest
    
Company
  
Type of Debt
  
Amount
  
Rate
  
Due Date
Issuances:
    
(in millions)
(%)
    
I&M
  
Notes Payable
  
$
 110 
  
Variable
  
2016 
I&M
  
Other Long-term Debt
    
 20 
(a)
Variable
  
2015 
PSO
  
Notes Payable
    
 2 
  
3.00 
  
2027 
SWEPCo
  
Senior Unsecured Notes
    
 275 
  
3.55 
  
2022 
SWEPCo
  
Notes Payable
    
 65 
  
4.58 
  
2032 
                   
Non-Registrant:
                  
TCC
  
Securitization Bonds
    
 312 
  
2.845 
  
2024 
TCC
  
Securitization Bonds
    
 308 
  
0.88 
  
2017 
TCC
  
Securitization Bonds
    
 180 
  
1.976 
  
2020 
Total Issuances
      
$
 1,272 
(b)
      

(a)
Consists of a $110 million three-year credit facility to be used for general corporate purposes.
(b)
Amount indicated on the statement of cash flows of $1,261 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
  
$
 30 
  
6.05 
  
2024 
APCo
  
Pollution Control Bonds
    
 20 
  
5.00 
  
2021 
I&M
  
Notes Payable
    
 14 
  
5.44 
  
2013 
I&M
  
Notes Payable
    
 11 
  
4.00 
  
2014 
I&M
  
Notes Payable
    
 11 
  
Variable
  
2015 
I&M
  
Notes Payable
    
 12 
  
Variable
  
2016 
I&M
  
Notes Payable
    
 8 
  
2.12 
  
2016 
OPCo
  
Pollution Control Bonds
    
 45 
  
4.85 
  
2012 
OPCo
  
Senior Unsecured Notes
    
 150 
  
Variable
  
2012 
SWEPCo
  
Notes Payable
    
 20 
  
7.03 
  
2012 
                   
Non-Registrant:
                  
AEP Subsidiaries
  
Notes Payable
    
 4 
  
Variable
  
2017 
AEP Subsidiaries
  
Notes Payable
    
 1 
  
7.59-8.03
  
2026 
AEGCo
  
Senior Unsecured Notes
    
 3 
  
6.33 
  
2037 
TCC
  
Securitization Bonds
    
 63 
  
4.98 
  
2013 
TCC
  
Securitization Bonds
    
 35 
  
5.96 
  
2013 
TCC
  
Pollution Control Bonds
    
 60 
  
1.125 
  
2012 
Total Retirements and
                  
Principal Payments
      
$
 487 
        

In July 2012, I&M retired $9 million of Notes Payable related to DCC Fuel.

In July 2012, TCC retired $73 million of Securitization Bonds.

As of June 30, 2012, trustees held, on our behalf, $583 million of our reacquired Pollution Control Bonds.
 
76
 
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 financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.  Specifically, several of our public utility subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%.

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 value of the common stock.  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, 2012
  
December 31, 2011
   
Outstanding
    
Interest
  
Outstanding
    
Interest
Type of Debt
  
Amount
    
Rate (a)
  
Amount
    
Rate (a)
   
(in millions)
          
(in millions)
          
Securitized Debt for Receivables (b)
     $ 658       0.27 %     $ 666       0.27  
%
Commercial Paper
       550       0.46 %       967       0.51  
%
Line of Credit – Sabine (c)
       -       - %       17       1.79  
%
Total Short-term Debt
     $ 1,208               $ 1,650            

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

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 3.
 
77
 
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 June 2012, AEP Credit renewed its receivables securitization agreement.  The agreement provides commitments of $700 million from bank conduits to finance receivables from AEP Credit.  A commitment of $385 million expires in June 2013 and the remaining commitment of $315 million expires in June 2015.

Accounts receivable information for AEP Credit is as follows:

 
Three Months Ended
  
Six Months Ended
  
 
June 30,
  
June 30,
  
 
2012
  
2011
  
2012
  
2011
  
 
(dollars in millions)
  
Effective Interest Rates on Securitization of
                        
Accounts Receivable
     0.26 %     0.26 %     0.26 %     0.28 %
Net Uncollectible Accounts Receivable
                                
Written Off
   $ 6     $ 6     $ 14     $ 17  

   
June 30,
    
December 31,
   
2012
    
2011
   
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
          
Less Uncollectible Accounts
   $ 888     $ 902
Total Principal Outstanding
     658       666
Delinquent Securitized Accounts Receivable
     35       38
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable
     21       18
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable
     355       370

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.

11.  SUSTAINABLE COST REDUCTIONS

In April 2012, we initiated a process to identify employee repositioning opportunities and efficiencies that will result in sustainable cost savings.  The process will result in involuntary severances and is expected to be completed by the end of 2012.  The severance program provides two weeks of base pay for every year of service along with other severance benefits.

We recorded a charge to expense in the second quarter of 2012 related to the sustainable cost reductions initiative.

   
Total
  
   
(in millions)
  
Incurred
  
$
 13 
  
Settled
    
 (5)
  
Remaining Balance at June 30, 2012
  
$
 8 
  

These expenses relate primarily to severance benefits.  They are included primarily in Other Operation on the income statement and Other Current Liabilities on the balance sheet.  Approximately 94% of the expense was within the Utility Operations segment.  At this time, we are unable to estimate the total amount to be incurred in future periods related to this initiative or to quantify the effects on future earnings, cash flows and financial condition.
 
78
 










APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
 
 
 
79
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Possible Termination of the Interconnection Agreement

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC.  It is unknown at this time whether the Interconnection Agreement 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.  Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future.  If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement 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.

Virginia Regulatory Activity

In April 2012, APCo filed an application with the Virginia SCC for an annual increase in fuel revenues of $117 million to be effective June 2012.  The filing included forecasted costs for the 15-month period ended August 2013 and requested recovery of APCo's anticipated unrecovered fuel balance as of May 2012 over a two-year period commencing in June 2012.  The non-incremental portion of APCo's forecasted and deferred wind purchased power costs were reflected in APCo's filing.  In June 2012, the Virginia SCC approved the application as filed.

West Virginia Regulatory Activity

In March 2012, West Virginia passed securitization legislation, which allows the WVPSC to establish a regulatory framework to securitize certain deferred Expanded Net Energy Charge (ENEC) balances and other ENEC related assets.  APCo and WPCo anticipate filing, in the third quarter of 2012, a request for a financing order with the WVPSC pursuant to the securitization legislation to securitize approximately $400 million.  See “APCo’s and WPCo’s Expanded Net Energy Charge (ENEC) Filing” section of Note 2.

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, the Virginia SCC and the FERC are required.  In December 2011 and February 2012, APCo and WPCo filed merger applications with the WVPSC and the FERC, respectively.  In February 2012, APCo and WPCo withdrew their merger application with the FERC.  Management intends to refile a merger application with the FERC and also file a merger application with the Virginia SCC in the future.  See “WPCo Merger with APCo” section of Note 2.

Storm Damage

In late June 2012 and early July 2012, APCo was significantly impacted by several severe storms.  In the second quarter of 2012, APCo recorded minimal incremental operation and maintenance expenses related to the June 2012 storms.  APCo expects to incur an estimated $95 million in total storm restoration costs in the third quarter of 2012, including an estimated $25 million in capital spending related to these storms and an estimated $70 million in incremental operation and maintenance costs.  APCo intends to defer the majority of the incremental operation and maintenance costs and seek future recovery.  If APCo is not ultimately permitted to recover these storm costs, it would reduce future net income and cash flows and impact financial condition.

 
80
 
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 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report.  Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 146.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 201 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,
 
2012 
  
2011 
  
2012 
  
2011 
     
(in millions of KWHs)
Retail:
                      
 
Residential
  
 2,184 
    
 2,367 
    
 5,634 
    
 6,326 
 
Commercial
  
 1,683 
    
 1,696 
    
 3,309 
    
 3,394 
 
Industrial
  
 2,702 
    
 2,699 
    
 5,306 
    
 5,318 
 
Miscellaneous
  
 201 
    
 204 
    
 402 
    
 414 
Total Retail (a)
  
 6,770 
    
 6,966 
    
 14,651 
    
 15,452 
                       
Wholesale
  
 1,492 
    
 2,336 
    
 2,873 
    
 4,163 
                       
Total KWHs
  
 8,262 
    
 9,302 
    
 17,524 
    
 19,615 
                           
(a)
Represents energy delivered to distribution customers.

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,
   
2012 
  
2011 
  
2012 
  
2011 
   
(in degree days)
Actual - Heating (a)
  
 61 
    
 56 
    
 983 
    
 1,387 
Normal - Heating (b)
  
 97 
    
 100 
    
 1,440 
    
 1,437 
                         
Actual - Cooling (c)
  
 419 
    
 464 
    
 444 
    
 470 
Normal - Cooling (b)
  
 354 
    
 348 
    
 360 
    
 354 
                         
(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.
 
 

 
 
81
 
 
Second Quarter of 2012 Compared to Second Quarter of 2011
 
Reconciliation of Second Quarter of 2011 to Second Quarter of 2012
Net Income
(in millions)
               
Second Quarter of 2011
        
$
 32 
               
Changes in Gross Margin:
            
Retail Margins
          
 52 
Off-system Sales
          
 (2)
Transmission Revenues
          
 2 
Other Revenues
          
 (2)
Total Change in Gross Margin
          
 50 
             
Changes in Expenses and Other:
            
Other Operation and Maintenance
          
 21 
Depreciation and Amortization
          
 (17)
Taxes Other Than Income Taxes
          
 1 
Carrying Costs Income
          
 (1)
Other Income
          
 (2)
Interest Expense
          
 1 
Total Change in Expenses and Other
          
 3 
               
Income Tax Expense
          
 (23)
               
Second Quarter of 2012
        
$
 62 

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 electricity were as follows:

 
·
Retail Margins increased $52 million primarily due to the following:
   
·
A $­­28 million increase due to lower capacity settlement expenses under the Interconnection Agreement, net of recovery in West Virginia and environmental deferrals in Virginia.  This increase was primarily as a result of a mild winter in 2012 and its impact on APCo’s winter peak, APCo’s completion of the Dresden Plant in January 2012 and the removal of Sporn Unit 5 from the Interconnection Agreement in the third quarter of 2011.
   
·
A $9 million increase due to higher rates in Virginia.
   
·
A $9 million increase of additional wind purchase recovery costs deferred as a result of the June 2012 Virginia SCC fuel factor order.
   
·
A $6 million increase in recoverable PJM expenses.
   
These increases were partially offset by:
   
·
A $7 million decrease in residential and commercial margins primarily due to lower non-weather related usage.
   
·
A $3 million decrease in weather-related usage primarily due to a 9% decrease in cooling degree days.
 
·
Margins from Off-system Sales decreased $2 million primarily due to lower physical sales volumes and lower trading and marketing margins.

 
82
 
Expenses and Other and Income Tax Expense changed between years as follows:

 
·
Other Operation and Maintenance expenses decreased $21 million primarily due to the following:
   
·
A $10 million decrease in distribution expenses resulting from storm damage repairs in 2011.
  
   
·
A $7 million decrease due to the deferral of transmission costs for the Virginia Transmission Rate Adjustment Clause.
  
   
·
A $6 million decrease due to lower boiler maintenance expenses in 2012 at all six APCo coal-fueled power plants.
  
   
These decreases were partially offset by:
   
·
A $3 million increase due to expenses related to the 2012 sustainable cost reductions.
  
 
·
Depreciation and Amortization expenses increased $17 million primarily due to:
   
·
A $10 million increase in depreciation as a result of increased depreciation rates in Virginia effective February 2012.
  
   
·
A $5 million increase in amortization primarily as a result of the Virginia E&R surcharge and the Virginia Environmental Rate Adjustment Clause, both effective February 2012.
  
 
·
Income Tax Expense increased $23 million primarily due to an increase in pretax book income.
 
 
83
 
Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011
 
Reconciliation of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2012
Net Income
(in millions)
               
Six Months Ended June 30, 2011
        
$
 71 
               
Changes in Gross Margin:
            
Retail Margins
          
 95 
Off-system Sales
          
 (6)
Transmission Revenues
          
 5 
Other Revenues
          
 (4)
Total Change in Gross Margin
          
 90 
             
Changes in Expenses and Other:
            
Other Operation and Maintenance
          
 46 
Depreciation and Amortization
          
 (29)
Taxes Other Than Income Taxes
          
 1 
Carrying Costs Income
          
 3 
Other Income
          
 (2)
Interest Expense
          
 3 
Total Change in Expenses and Other
          
 22 
               
Income Tax Expense
          
 (45)
               
Six Months Ended June 30, 2012
        
$
 138 

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 electricity were as follows:

 
·
Retail Margins increased $95 million primarily due to the following:
   
·
A $55 million increase due to lower capacity settlement expenses under the Interconnection Agreement, net of recovery in West Virginia and environmental deferrals in Virginia.  This increase was primarily as a result of a mild winter in 2012 and its impact on APCo’s winter peak, APCo’s completion of the Dresden Plant in January 2012 and the removal of Sporn Unit 5 from the Interconnection Agreement in the third quarter of 2011.
   
·
A $31 million increase due to higher base rates in Virginia and West Virginia.
   
·
An $18 million increase in other variable electric generation expenses.
   
·
A $13 million increase in recoverable PJM expenses.
   
·
A $9 million increase of additional wind purchase recovery costs deferred as a result of the June 2012 Virginia SCC fuel factor order.
   
These increases were partially offset by:
   
·
A $33 million decrease in weather-related usage primarily due to a 31% decrease in heating degree days.
   
·
An $8 million decrease in residential and commercial margins primarily due to lower non-weather related usage.
 
·
Margins from Off-system Sales decreased $6 million primarily due to lower physical sales volumes and lower trading and marketing margins.
 
·
Transmission Revenues increased $5 million primarily due to increased Network Transmission Service revenue requirements beginning in July 2011.
 
·
Other Revenues decreased $4 million primarily due to gains on sales of SO2 allowances in the first quarter of 2011.

 
84
 
Expenses and Other and Income Tax Expense changed between years as follows:

 
·
Other Operation and Maintenance expenses decreased $46 million primarily due to the following:
    · A $41 million decrease 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 $14 million decrease due to the deferral of transmission costs for the Virginia Transmission Rate Adjustment Clause.
  
   
·
An $11 million decrease due to 2011 storm expenses.
  
   
·
A $7 million decrease due to lower boiler maintenance expenses in 2012 at all six APCo coal-fueled power plants.
  
   
These decreases were partially offset by:
  
   
·
A $32 million increase due to the first quarter 2011 deferral of 2009 storm costs and the 2010 cost reduction initiatives as allowed by the WVPSC in 2011.
  
   
·
A $3 million increase due to expenses related to the 2012 sustainable cost reductions.
  
 
·
Depreciation and Amortization expenses increased $29 million primarily due to:
   
·
A $17 million increase in depreciation as a result of increased depreciation rates in Virginia effective February 2012.
  
   
·
A $9 million increase in amortization primarily as a result of the Virginia E&R surcharge and the Virginia Environmental Rate Adjustment Clause, both effective February 2012.
  
 
·
Carrying Costs Income increased $3 million primarily due to carrying charges on the Dresden Plant resulting from the Virginia Generation Rate Adjustment Clause and the West Virginia Expanded Net Energy Charge.
 
·
Interest Expense decreased $3 million primarily due to lower interest rates on long-term debt.
 
·
Income Tax Expense increased $45 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 Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2011 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 Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of accounting pronouncements.
 
 
85
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
  
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
  
For the Three and Six Months Ended June 30, 2012 and 2011
  
(in thousands)
  
(Unaudited)
  
   
   
Three Months Ended
    
Six Months Ended
  
   
2012
    
2011
    
2012
    
2011
  
REVENUES
                        
Electric Generation, Transmission and Distribution
   $ 647,236     $ 666,785     $ 1,385,835     $ 1,417,797  
Sales to AEP Affiliates
     67,043       82,531       131,344       161,222  
Other Revenues
     2,182       2,129       4,758       4,246  
TOTAL REVENUES
     716,461       751,445       1,521,937       1,583,265  
                                 
EXPENSES
                                
Fuel and Other Consumables Used for Electric Generation
     181,653       184,698       368,537       365,279  
Purchased Electricity for Resale
     44,869       69,127       110,225       138,345  
Purchased Electricity from AEP Affiliates
     125,864       183,661       281,881       407,850  
Other Operation
     72,685       74,617       147,004       187,893  
Maintenance
     37,830       57,163       84,165       89,456  
Depreciation and Amortization
     85,139       67,644       165,552       136,743  
Taxes Other Than Income Taxes
     24,995       25,968       51,957       53,071  
TOTAL EXPENSES
     573,035       662,878       1,209,321       1,378,637  
                                 
OPERATING INCOME
     143,426       88,567       312,616       204,628  
                                 
Other Income (Expense):
                                
Interest Income
     359       762       702       1,082  
Carrying Costs Income
     5,467       6,542       13,252       9,981  
Allowance for Equity Funds Used During Construction
     4       1,212       517       2,095  
Interest Expense
     (51,945 )     (53,188 )     (103,252 )     (106,127 )
                                 
INCOME BEFORE INCOME TAX EXPENSE
     97,311       43,895       223,835       111,659  
                                 
Income Tax Expense
     34,979       12,268       86,192       41,052  
                                 
NET INCOME
     62,332       31,627       137,643       70,607  
                                 
Preferred Stock Dividend Requirements Including Capital
                                
Stock Expense
     -       200       -       400  
                                 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
   $ 62,332     $ 31,427     $ 137,643     $ 70,207  
   
The common stock of APCo is wholly-owned by AEP.
  
   
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
  
 
 
 
 
86
 
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
  
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
  
For the Three and Six Months Ended June 30, 2012 and 2011
  
(in thousands)
  
(Unaudited)
  
                   
   
Three Months Ended
  
Six Months Ended
  
   
2012
  
2011
  
2012
  
2011
  
Net Income
   $ 62,332   $ 31,627   $ 137,643   $ 70,607  
                           
OTHER COMPREHENSIVE INCOME, NET OF TAXES
                          
Cash Flow Hedges, Net of Tax of $305 and $377 for the Three Months Ended
                          
June 30, 2012 and 2011, Respectively, and $15 and $652 for the Six
                          
Months Ended June 30, 2012 and 2011, Respectively
     566     700     27     1,211  
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $484
                          
and $419 for the Three Months Ended June 30, 2012 and 2011,
                          
Respectively, and $969 and $837 for the Six Months Ended June 30,
                          
2012 and 2011, Respectively
     899     777     1,799     1,554  
                           
TOTAL OTHER COMPREHENSIVE INCOME
     1,465     1,477     1,826     2,765  
                           
TOTAL COMPREHENSIVE INCOME
   $ 63,797   $ 33,104   $ 139,469   $ 73,372  
                           
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
  
 
 
 
87
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)
                                     
                           
Accumulated
    
                           
Other
    
         
Common
  
Paid-in
  
Retained
  
Comprehensive
    
         
Stock
  
Capital
  
Earnings
  
Income (Loss)
  
Total
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)
Capital Stock Expense
          
 3 
                
 3 
Subtotal – Common Shareholder's Equity
                            
 2,753,782 
                                     
Net Income
                
 70,607 
          
 70,607 
Other Comprehensive Income
                      
 2,765 
    
 2,765 
TOTAL COMMON SHAREHOLDER'S EQUITY –
                              
 
JUNE 30, 2011
  
$
 260,458 
  
$
 1,475,499 
  
$
 1,136,455 
  
$
 (45,258)
  
$
 2,827,154 
                                     
TOTAL COMMON SHAREHOLDER'S EQUITY –
                              
 
DECEMBER 31, 2011
  
$
 260,458 
  
$
 1,573,752 
  
$
 1,160,747 
  
$
 (58,543)
  
$
 2,936,414 
                                     
Common Stock Dividends
                
 (100,000)
          
 (100,000)
Subtotal – Common Shareholder's Equity
                            
 2,836,414 
                                     
Net Income
                
 137,643 
          
 137,643 
Other Comprehensive Income
                      
 1,826 
    
 1,826 
TOTAL COMMON SHAREHOLDER'S EQUITY –
                              
 
JUNE 30, 2012
  
$
 260,458 
  
$
 1,573,752 
  
$
 1,198,390 
  
$
 (56,717)
  
$
 2,975,883 
                                     
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
      
 

 
 
88
 
 
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)
 
   
2012 
  
2011 
CURRENT ASSETS
            
Cash and Cash Equivalents
  
$
 2,109 
  
$
 2,317 
Advances to Affiliates
    
 22,573 
    
 22,008 
Accounts Receivable:
            
 
Customers
    
 145,133 
    
 158,382 
 
Affiliated Companies
    
 70,561 
    
 136,194 
 
Accrued Unbilled Revenues
    
 47,419 
    
 68,427 
 
Miscellaneous
    
 456 
    
 5,505 
 
Allowance for Uncollectible Accounts
    
 (4,413)
    
 (5,289)
   
Total Accounts Receivable
    
 259,156 
    
 363,219 
Fuel
    
 197,342 
    
 143,931 
Materials and Supplies
    
 103,267 
    
 101,724 
Risk Management Assets
    
 41,841 
    
 39,645 
Accrued Tax Benefits
    
 320 
    
 7,715 
Regulatory Asset for Under-Recovered Fuel Costs
    
 102,091 
    
 41,105 
Prepayments and Other Current Assets
    
 18,857 
    
 21,745 
TOTAL CURRENT ASSETS
    
 747,556 
    
 743,409 
             
PROPERTY, PLANT AND EQUIPMENT
            
Electric:
            
 
Generation
    
 5,563,066 
    
 5,194,967 
 
Transmission
    
 2,007,141 
    
 1,943,969 
 
Distribution
    
 2,901,775 
    
 2,845,405 
Other Property, Plant and Equipment
    
 373,255 
    
 357,326 
Construction Work in Progress
    
 217,902 
    
 565,841 
Total Property, Plant and Equipment
    
 11,063,139 
    
 10,907,508 
Accumulated Depreciation and Amortization
    
 3,087,299 
    
 2,994,016 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    
 7,975,840 
    
 7,913,492 
                 
OTHER NONCURRENT ASSETS
            
Regulatory Assets
    
 1,404,116 
    
 1,481,193 
Long-term Risk Management Assets
    
 44,676 
    
 39,226 
Deferred Charges and Other Noncurrent Assets
    
 110,514 
    
 122,187 
TOTAL OTHER NONCURRENT ASSETS
    
 1,559,306 
    
 1,642,606 
             
TOTAL ASSETS
  
$
 10,282,702 
  
$
 10,299,507 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
 
89
 
 
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2012 and December 31, 2011
(Unaudited)
 
   
2012 
  
2011 
     
(in thousands)
CURRENT LIABILITIES
            
Advances from Affiliates
  
$
 166,988 
  
$
 198,248 
Accounts Payable:
            
 
General
    
 139,851 
    
 186,612 
 
Affiliated Companies
    
 107,129 
    
 137,376 
Long-term Debt Due Within One Year – Nonaffiliated
    
 545,027 
    
 594,525 
Risk Management Liabilities
    
 23,036 
    
 26,606 
Customer Deposits
    
 60,971 
    
 61,690 
Deferred Income Taxes
    
 38,857 
    
 14,255 
Accrued Taxes
    
 85,479 
    
 63,422 
Accrued Interest
    
 56,561 
    
 57,230 
Other Current Liabilities
    
 88,886 
    
 105,646 
TOTAL CURRENT LIABILITIES
    
 1,312,785 
    
 1,445,610 
             
NONCURRENT LIABILITIES
            
Long-term Debt – Nonaffiliated
    
 3,132,089 
    
 3,131,726 
Long-term Risk Management Liabilities
    
 22,638 
    
 12,923 
Deferred Income Taxes
    
 1,766,932 
    
 1,736,180 
Regulatory Liabilities and Deferred Investment Tax Credits
    
 620,058 
    
 576,792 
Employee Benefits and Pension Obligations
    
 296,168 
    
 302,182 
Deferred Credits and Other Noncurrent Liabilities
    
 156,149 
    
 157,680 
TOTAL NONCURRENT LIABILITIES
    
 5,994,034 
    
 5,917,483 
             
TOTAL LIABILITIES
    
 7,306,819 
    
 7,363,093 
             
Rate Matters (Note 2)
    
 
    
 
Commitments and Contingencies (Note 3)
    
 
    
 
             
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
    
 1,573,752 
    
 1,573,752 
Retained Earnings
    
 1,198,390 
    
 1,160,747 
Accumulated Other Comprehensive Income (Loss)
    
 (56,717)
    
 (58,543)
TOTAL COMMON SHAREHOLDER’S EQUITY
    
 2,975,883 
    
 2,936,414 
             
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
  
$
 10,282,702 
  
$
 10,299,507 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
90
 
 
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)
 
   
2012 
  
2011 
OPERATING ACTIVITIES
            
Net Income
  
$
 137,643 
  
$
 70,607 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
            
   
Depreciation and Amortization
    
 165,552 
    
 136,743 
   
Deferred Income Taxes
    
 56,927 
    
 127,525 
   
Carrying Costs Income
    
 (13,252)
    
 (9,981)
   
Allowance for Equity Funds Used During Construction
    
 (517)
    
 (2,095)
   
Mark-to-Market of Risk Management Contracts
    
 (2,323)
    
 7,343 
   
Fuel Over/Under-Recovery, Net
    
 26,417 
    
 (21,132)
   
Change in Other Noncurrent Assets
    
 (16,708)
    
 11,361 
   
Change in Other Noncurrent Liabilities
    
 18,266 
    
 5,239 
   
Changes in Certain Components of Working Capital:
            
     
Accounts Receivable, Net
    
 103,680 
    
 84,748 
     
Fuel, Materials and Supplies
    
 (54,954)
    
 85,449 
     
Accounts Payable
    
 (43,538)
    
 (62,795)
     
Accrued Taxes, Net
    
 30,032 
    
 (56,411)
     
Other Current Assets
    
 2,579 
    
 6,281 
     
Other Current Liabilities
    
 (15,880)
    
 3,316 
Net Cash Flows from Operating Activities
    
 393,924 
    
 386,198 
             
INVESTING ACTIVITIES
            
Construction Expenditures
    
 (212,959)
    
 (191,125)
Change in Advances to Affiliates, Net
    
 (565)
    
 (162,787)
Other Investing Activities
    
 3,158 
    
 7,832 
Net Cash Flows Used for Investing Activities
    
 (210,366)
    
 (346,080)
             
FINANCING ACTIVITIES
            
Issuance of Long-term Debt – Nonaffiliated
    
 - 
    
 640,164 
Change in Advances from Affiliates, Net
    
 (31,260)
    
 (128,331)
Retirement of Long-term Debt – Nonaffiliated
    
 (49,512)
    
 (479,661)
Retirement of Cumulative Preferred Stock
    
 - 
    
 (8)
Principal Payments for Capital Lease Obligations
    
 (3,258)
    
 (3,720)
Dividends Paid on Common Stock
    
 (100,000)
    
 (67,500)
Dividends Paid on Cumulative Preferred Stock
    
 - 
    
 (400)
Other Financing Activities
    
 264 
    
 19 
Net Cash Flows Used for Financing Activities
    
 (183,766)
    
 (39,437)
             
Net Increase (Decrease) in Cash and Cash Equivalents
    
 (208)
    
 681 
Cash and Cash Equivalents at Beginning of Period
    
 2,317 
    
 951 
Cash and Cash Equivalents at End of Period
  
$
 2,109 
  
$
 1,632 
             
SUPPLEMENTARY INFORMATION
            
Cash Paid for Interest, Net of Capitalized Amounts
  
$
 100,319 
  
$
 100,127 
Net Cash Paid (Received) for Income Taxes
    
 (10,090)
    
 (33,371)
Noncash Acquisitions Under Capital Leases
    
 1,265 
    
 565 
Government Grants Included in Accounts Receivable at June 30,
    
 - 
    
 4,061 
Construction Expenditures Included in Current Liabilities at June 30,
    
 30,439 
    
 52,421 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
91
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to APCo’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 APCo.  The footnotes begin on page 146.

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

 
92
 




INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES

 
93
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Possible Termination of the Interconnection Agreement

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC.  It is unknown at this time whether the Interconnection Agreement 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.  Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future.  If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement 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.

Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on common equity of 11.15%.  The $149 million net annual increase reflects an increase in base rates of $178 million offset by proposed corresponding reductions of $13 million to the off-system sales sharing rider, $9 million to the PJM cost rider and $7 million to the clean coal technology rider rates.  The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.

In May 2012, the Indiana Office of Utility Consumer Counselor filed testimony that recommended an increase in base rates of $28 million, excluding reductions to certain riders, based upon a return on common equity of 9.2%.  I&M filed rebuttal testimony in May 2012 which supported an increase of $170 million in base rates, excluding reductions to certain riders.  Final hearings were held in June 2012.  A decision from the IURC is expected in the fourth quarter of 2012.  See “2011 Indiana Base Rate Case” section of Note 2.

Storm Damage

In late June 2012 and early July 2012, I&M was significantly impacted by several severe storms.  In the second quarter of 2012, I&M recorded minimal incremental operation and maintenance expenses related to the June 2012 storms.  I&M expects to incur an estimated $20 million in total storm restoration costs in the third quarter of 2012, including an estimated $5 million in capital spending related to these storms and an estimated $15 million in incremental operation and maintenance costs.  Management is currently evaluating whether I&M will pursue recovery for the incremental operation and maintenance costs in the future.

Michigan Capacity Rate

In April 2012, the FERC issued an order, effective October 2012, which sets I&M's capacity cost to be charged to alternative electric suppliers (AES) serving switching customers in I&M's Michigan service territory at $394/MW day unless a state compensation mechanism is set by the MPSC.  In May 2012, the MPSC issued an order to initiate a proceeding to establish a cost of service state compensation mechanism for the capacity rate to be charged to AES.  I&M filed its cost of service proposal in June 2012.  Under Michigan law, switching is limited to 10% of I&M's Michigan load, which was achieved in June 2012, the second month of customer switching.  I&M is currently receiving compensation through PJM from billings to AES at the Reliability Pricing Model rate, which is less than I&M’s cost of service by approximately $8 million annually.

 
94
 
Cook Plant

Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator.  Repair of the property damage and replacement of the turbine rotors and other equipment cost approximately $400 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.  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 would reduce future net income and cash flows and impact financial condition.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 3.

Nuclear Regulatory Commission

As a result of the nuclear plant situation in Japan following a March 2011 earthquake, the Nuclear Regulatory Commission (NRC) initiated a review of 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.  The NRC is also looking into the fuel used at eleven reactors, including the units at the Cook Plant.  Their concern relates to fuel temperatures if abnormal conditions are experienced.  Management continues to monitor this issue and responds to the NRC’s inquiry, as necessary. In addition to the review by the NRC, Congress could consider legislation tightening oversight of nuclear generating facilities.  Management is unable to predict the impact of potential future regulation of nuclear facilities.

Life Cycle Management Project

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects for Cook Plant Units 1 and 2.  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.

In Indiana, I&M requested recovery of certain project costs, including interest, through a rider effective January 2013.  In Michigan, I&M requested that the MPSC approve a Certificate of Public Convenience and Necessity and authorize I&M to defer, on an interim basis, incremental depreciation and property tax costs, including interest, along with study, analysis and development costs until the applicable costs are included in I&M’s base rates.  As of June 30, 2012, I&M has incurred $92 million related to the LCM Project.  If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

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 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report.  Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 146.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 201 for additional discussion of relevant factors.

 
95
 
RESULTS OF OPERATIONS
                      
                           
KWH Sales/Degree Days
                      
                           
Summary of KWH Energy Sales
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
 
2012 
  
2011 
  
2012 
  
2011 
     
(in millions of KWHs)
Retail:
                      
 
Residential
  
 1,217 
    
 1,170 
    
 2,786 
    
 3,006 
 
Commercial
  
 1,290 
    
 1,188 
    
 2,456 
    
 2,452 
 
Industrial
  
 1,964 
    
 1,871 
    
 3,797 
    
 3,715 
 
Miscellaneous
  
 15 
    
 15 
    
 38 
    
 38 
Total Retail (a)
  
 4,486 
    
 4,244 
    
 9,077 
    
 9,211 
                       
Wholesale
  
 2,068 
    
 2,408 
    
 4,029 
    
 4,504 
                       
Total KWHs
  
 6,554 
    
 6,652 
    
 13,106 
    
 13,715 
                           
(a)
Represents energy delivered to distribution customers.

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,
   
2012 
  
2011 
  
2012 
  
2011 
   
(in degree days)
Actual - Heating (a)
  
 163 
    
 228 
    
 1,784 
    
 2,620 
Normal - Heating (b)
  
 235 
    
 238 
    
 2,420 
    
 2,414 
                         
Actual - Cooling (c)
  
 369 
    
 304 
    
 398 
    
 304 
Normal - Cooling (b)
  
 256 
    
 252 
    
 257 
    
 253 
                         
(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.
 
 
 
96
 
 
Second Quarter of 2012 Compared to Second Quarter of 2011
 
Reconciliation of Second Quarter of 2011 to Second Quarter of 2012
Net Income
(in millions)
               
Second Quarter of 2011
        
$
 31 
               
Changes in Gross Margin:
            
Retail Margins
          
 10 
FERC Municipals and Cooperatives
          
 (1)
Off-system Sales
          
 (4)
Transmission Revenues
          
 1 
Other Revenues
          
 (2)
Total Change in Gross Margin
          
 4 
             
Changes in Expenses and Other:
            
Other Operation and Maintenance
          
 (1)
Depreciation and Amortization
          
 (4)
Taxes Other Than Income Taxes
          
 2 
Other Income
          
 (1)
Interest Expense
          
 (1)
Total Change in Expenses and Other
          
 (5)
               
Second Quarter of 2012
        
$
 30 

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 electricity were as follows:

 
·
Retail Margins increased $10 million primarily due to the following:
   
·
A $10 million increase due to industrial and commercial usage.
   
·
A $6 million increase due to customer credits issued in 2011 for a settlement relating to the Cook Plant Unit 1 (Unit 1) fire outage.  This increase was offset by an increase in Other Operation and Maintenance expenses as discussed below.
   
·
A $4 million increase in rate recovery primarily due to higher PJM rider revenue.  The increase in PJM revenues is offset by a corresponding increase in Other Operation and Maintenance expenses below.
   
·
A $3 million increase due to a decrease in the AEGCo power bill.
   
These increases were partially offset by:
   
·
A $16 million decrease in capacity settlement revenues under the Interconnection Agreement, net of sharing with customers in Michigan.  This decrease was primarily a result of a mild winter in 2012 and its impact on APCo’s winter peak.
 
·
Margins from FERC Municipals and Cooperatives decreased $1 million primarily due to the following:
   
·
An $11 million decrease due to an annual base rate adjustment to actual costs.
   
This decrease was partially offset by:
   
·
A $10 million increase due to favorable fuel adjustments.
 
·
Margins from Off-system Sales decreased $4 million primarily due to lower physical sales volumes and lower trading and marketing margins.

Expenses and Other changed between years as follows:

 
·
Other Operation and Maintenance expenses increased $1 million primarily due to the following:
   
·
A $6 million increase in steam power expenses related to the Unit 1 fire outage.  This increase was offset by an increase in Retail Margins as discussed above.
   
This increase was partially offset by:
   
·
A $4 million decrease due to maintenance outages at the Tanners Creek and Rockport plants in 2011.
 
·
Depreciation and Amortization expenses increased $4 million primarily due to higher depreciation rates reflecting a change in Tanners Creek Plant’s estimated life as approved in the Michigan base case settlement effective April 2012.
 
 
 
97
 

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011
 
Reconciliation of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2012
Net Income
(in millions)
               
Six Months Ended June 30, 2011
        
$
 77 
               
Changes in Gross Margin:
            
Retail Margins
          
 (20)
FERC Municipals and Cooperatives
          
 (2)
Off-system Sales
          
 (8)
Transmission Revenues
          
 2 
Other Revenues
          
 5 
Total Change in Gross Margin
          
 (23)
             
Changes in Expenses and Other:
            
Other Operation and Maintenance
          
 5 
Depreciation and Amortization
          
 (4)
Taxes Other Than Income Taxes
          
 2 
Interest Expense
          
 (1)
Total Change in Expenses and Other
          
 2 
               
Income Tax Expense
          
 13 
               
Six Months Ended June 30, 2012
        
$
 69 

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 electricity were as follows:

 
·
Retail Margins decreased $20 million primarily due to the following:
   
·
A $29 million decrease in capacity settlement revenues under the Interconnection Agreement, net of sharing with customers in Michigan.  This decrease was primarily a result of a mild winter in 2012 and its impact on APCo’s winter peak.
   
·
A $9 million decrease primarily due to lower commercial prices and lower residential usage.
   
·
A $7 million decrease in weather-related usage primarily due to a 32% decrease in heating degree days.
   
These decreases were offset by:
   
·
A $19 million increase in rate recovery primarily due to higher PJM rider revenue, Michigan base rate increases and higher Indiana Demand Side Management (DSM) revenue.  The increase in PJM and DSM revenues is offset by a corresponding increase in Other Operation and Maintenance expenses as discussed below.
   
·
A $6 million increase due to customer credits issued in 2011 for a settlement relating to the Unit 1 fire outage.  This increase was offset by an increase in Other Operation and Maintenance expenses as discussed below.
 
·
Margins from FERC Municipals and Cooperatives decreased $2 million primarily due to the following:
   
·
A $10 million decrease due to an annual base rate adjustment to actual costs.
   
This decrease was partially offset by:
   
·
An $8 million increase due to favorable fuel adjustments.
 
·
Margins from Off-system Sales decreased $8 million primarily due to lower physical sales volumes and lower trading and marketing margins.
 
·
Other Revenues increased $5 million primarily due to increased I&M’s River Transportation Division (RTD) revenues from barging activities.  This increase in RTD revenue was offset by a corresponding increase in Other Operation and Maintenance expenses from barging activities as discussed below.

 
98
 
Expenses and Other and Income Tax Expense changed between years as follows:

 
·
Other Operation and Maintenance expenses decreased $5 million primarily due to the following:
   
·
A $10 million decrease due to maintenance outages at the Tanners Creek and Rockport plants in 2011.
   
·
A $5 million decrease in distribution expenses primarily due to decreased overhead line expenses.
   
These decreases were partially offset by:
   
·
A $6 million increase in steam power expenses related to the Unit 1 fire outage.  This increase was offset by a corresponding increase in Retail Margins as discussed above.
   
·
A $4 million increase in PJM and DSM expenses.  The increase in PJM and DSM expenses was offset by a corresponding increase in Retail Margins as discussed above.
   
·
A $2 million increase in RTD expenses from barging activities.  The increase in RTD expense was offset by a corresponding increase in Other Revenues from barging activities as discussed above.
 
·
Depreciation and Amortization expenses increased $4 million primarily due to higher depreciation rates reflecting a change in Tanners Creek Plant’s estimated life as approved in the Michigan base case settlement effective April 2012.
 
·
Income Tax Expense decreased $13 million primarily due to a decrease in pretax book income, the regulatory accounting treatment of state income taxes and federal income tax adjustments recorded in 2011 related to prior year tax returns.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2011 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 Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of accounting pronouncements.
 
 
99
 
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
  
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
  
For the Three and Six Months Ended June 30, 2012 and 2011
  
(in thousands)
  
(Unaudited)
  
   
   
Three Months Ended
    
Six Months Ended
  
   
2012
    
2011
    
2012
    
2011
  
REVENUES
                        
Electric Generation, Transmission and Distribution
   $ 435,965     $ 419,627     $ 871,992     $ 876,489  
Sales to AEP Affiliates
     45,728       70,902       121,643       145,770  
Other Revenues - Affiliated
     29,052       28,133       59,763       52,464  
Other Revenues - Nonaffiliated
     131       2,816       3,685       7,247  
TOTAL REVENUES
     510,876       521,478       1,057,083       1,081,970  
                                 
EXPENSES
                                
Fuel and Other Consumables Used for Electric Generation
     96,715       108,322       209,085       223,384  
Purchased Electricity for Resale
     29,488       31,796       65,398       61,088  
Purchased Electricity from AEP Affiliates
     82,188       82,967       170,141       162,551  
Other Operation
     134,274       132,846       269,490       266,057  
Maintenance
     47,244       47,536       89,509       98,536  
Depreciation and Amortization
     37,560       33,263       71,539       67,350  
Taxes Other Than Income Taxes
     18,604       20,397       40,793       42,659  
TOTAL EXPENSES
     446,073       457,127       915,955       921,625  
                                 
OPERATING INCOME
     64,803       64,351       141,128       160,345  
                                 
Other Income (Expense):
                                
Other Income
     2,848       3,467       7,110       7,362  
Interest Expense
     (25,373 )     (24,193 )     (50,426 )     (49,384 )
                                 
INCOME BEFORE INCOME TAX EXPENSE
     42,278       43,625       97,812       118,323  
                                 
Income Tax Expense
     12,468       12,239       28,781       41,510  
                                 
NET INCOME
     29,810       31,386       69,031       76,813  
                                 
Preferred Stock Dividend Requirements
     -       85       -       170  
                                 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
   $ 29,810     $ 31,301     $ 69,031     $ 76,643  
                                 
The common stock of I&M is wholly-owned by AEP.
                                
                                 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
  
 
 
 
100
 

 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
  
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
  
For the Three and Six Months Ended June 30, 2012 and 2011
  
(in thousands)
  
(Unaudited)
  
                   
   
Three Months Ended
  
Six Months Ended
  
   
2012
  
2011
  
2012
  
2011
  
Net Income
   $ 29,810   $ 31,386   $ 69,031   $ 76,813  
                           
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                          
Cash Flow Hedges, Net of Tax of ($4,002) and $284 for the Three Months Ended
                          
June 30, 2012 and 2011, Respectively, and ($2,680) and $570 for the Six
                          
Months Ended June 30, 2012 and 2011, Respectively
     (7,433 )   528     (4,977 )   1,059  
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $150
                          
and $127 for the Three Months Ended June 30, 2012 and 2011,
                          
Respectively, and $300 and $255 for the Six Months Ended June 30, 2012
                          
and 2011, Respectively
     278     236     557     473  
                           
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
     (7,155 )   764     (4,420 )   1,532  
                           
TOTAL COMPREHENSIVE INCOME
   $ 22,655   $ 32,150   $ 64,611   $ 78,345  
                           
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
  
 
 
 
101
 

 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)
 
                     
Accumulated
    
                     
Other
    
   
Common
  
Paid-in
  
Retained
  
Comprehensive
    
         
Stock
  
Capital
  
Earnings
  
Income (Loss)
  
Total
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)
Subototal – Common Shareholder's Equity
                            
 1,656,679 
                               
Net Income
                
 76,813 
          
 76,813 
Other Comprehensive Income
                      
 1,532 
    
 1,532 
TOTAL COMMON SHAREHOLDER'S
                              
 
EQUITY – JUNE 30, 2011
  
$
 56,584 
  
$
 981,294 
  
$
 716,503 
  
$
 (19,357)
  
$
 1,735,024 
                               
TOTAL COMMON SHAREHOLDER'S
                              
 
EQUITY – DECEMBER 31, 2011
  
$
 56,584 
  
$
 980,896 
  
$
 751,721 
  
$
 (28,221)
  
$
 1,760,980 
                               
Common Stock Dividends
                
 (25,000)
          
 (25,000)
Subototal – Common Shareholder's Equity
                            
 1,735,980 
                               
Net Income
                
 69,031 
          
 69,031 
Other Comprehensive Loss
                      
 (4,420)
    
 (4,420)
TOTAL COMMON SHAREHOLDER'S
                              
 
EQUITY – JUNE 30, 2012
  
$
 56,584 
  
$
 980,896 
  
$
 795,752 
  
$
 (32,641)
  
$
 1,800,591 
                               
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
 
102
 

 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)
 
   
2012 
  
2011 
CURRENT ASSETS
            
Cash and Cash Equivalents
  
$
 898 
  
$
 1,020 
Advances to Affiliates
    
 238,466 
    
 95,714 
Accounts Receivable:
            
 
Customers
    
 67,410 
    
 72,461 
 
Affiliated Companies
    
 69,138 
    
 90,980 
 
Accrued Unbilled Revenues
    
 19,088 
    
 14,780 
 
Miscellaneous
    
 13,631 
    
 22,685 
 
Allowance for Uncollectible Accounts
    
 (1,725)
    
 (1,750)
   
Total Accounts Receivable
    
 167,542 
    
 199,156 
Fuel
    
 68,321 
    
 52,979 
Materials and Supplies
    
 170,538 
    
 175,924 
Risk Management Assets
    
 39,058 
    
 32,152 
Accrued Tax Benefits
    
 16,769 
    
 38,425 
Deferred Cook Plant Fire Costs
    
 64,435 
    
 63,809 
Prepayments and Other Current Assets
    
 41,256 
    
 35,395 
TOTAL CURRENT ASSETS
    
 807,283 
    
 694,574 
             
PROPERTY, PLANT AND EQUIPMENT
            
Electric:
            
 
Generation
    
 3,932,503 
    
 3,932,472 
 
Transmission
    
 1,261,018 
    
 1,224,786 
 
Distribution
    
 1,506,629 
    
 1,481,608 
Other Property, Plant and Equipment (Including Nuclear Fuel and Coal Mining)
    
 667,272 
    
 709,558 
Construction Work in Progress
    
 254,149 
    
 236,096 
Total Property, Plant and Equipment
    
 7,621,571 
    
 7,584,520 
Accumulated Depreciation, Depletion and Amortization
    
 3,196,749 
    
 3,179,920 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    
 4,424,822 
    
 4,404,600 
             
OTHER NONCURRENT ASSETS
            
Regulatory Assets
    
 599,542 
    
 602,979 
Spent Nuclear Fuel and Decommissioning Trusts
    
 1,657,502 
    
 1,591,732 
Long-term Risk Management Assets
    
 31,408 
    
 29,362 
Deferred Charges and Other Noncurrent Assets
    
 64,510 
    
 69,309 
TOTAL OTHER NONCURRENT ASSETS
    
 2,352,962 
    
 2,293,382 
             
TOTAL ASSETS
  
$
 7,585,067 
  
$
 7,392,556 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
 
103
 
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2012 and December 31, 2011
(dollars in thousands)
(Unaudited)
 
       
2012 
  
2011 
CURRENT LIABILITIES
            
Accounts Payable:
            
 
General
  
$
 78,758 
  
$
 113,063 
 
Affiliated Companies
    
 65,145 
    
 81,102 
Long-term Debt Due Within One Year – Nonaffiliated
            
 
(June 30, 2012 and December 31, 2011 Amounts Include $125,241 and
            
 
$101,620, Respectively, Related to DCC Fuel)
    
 303,240 
    
 279,075 
Risk Management Liabilities
    
 34,239 
    
 16,980 
Customer Deposits
    
 30,543 
    
 30,696 
Accrued Taxes
    
 63,380 
    
 65,233 
Accrued Interest
    
 27,839 
    
 27,798 
Other Current Liabilities
    
 85,437 
    
 117,879 
TOTAL CURRENT LIABILITIES
    
 688,581 
    
 731,826 
             
NONCURRENT LIABILITIES
            
Long-term Debt – Nonaffiliated
    
 1,828,261 
    
 1,778,600 
Long-term Risk Management Liabilities
    
 15,908 
    
 18,871 
Deferred Income Taxes
    
 968,806 
    
 925,712 
Regulatory Liabilities and Deferred Investment Tax Credits
    
 955,482 
    
 875,202 
Asset Retirement Obligations
    
 1,039,442 
    
 1,013,122 
Deferred Credits and Other Noncurrent Liabilities
    
 287,996 
    
 288,243 
TOTAL NONCURRENT LIABILITIES
    
 5,095,895 
    
 4,899,750 
             
TOTAL LIABILITIES
    
 5,784,476 
    
 5,631,576 
             
Rate Matters (Note 2)
            
Commitments and Contingencies (Note 3)
            
             
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
    
 980,896 
    
 980,896 
Retained Earnings
    
 795,752 
    
 751,721 
Accumulated Other Comprehensive Income (Loss)
    
 (32,641)
    
 (28,221)
TOTAL COMMON SHAREHOLDER’S EQUITY
    
 1,800,591 
    
 1,760,980 
             
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
  
$
 7,585,067 
  
$
 7,392,556 
     
 
    
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
 
104
 
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)
 
   
2012 
  
2011 
OPERATING ACTIVITIES
            
Net Income
  
$
 69,031 
  
$
 76,813 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
            
   
Depreciation and Amortization
    
 71,539 
    
 67,350 
   
Deferred Income Taxes
    
 40,899 
    
 42,561 
   
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net
    
 (9,163)
    
 23,086 
   
Allowance for Equity Funds Used During Construction
    
 (5,335)
    
 (7,440)
   
Mark-to-Market of Risk Management Contracts
    
 (2,798)
    
 6,183 
   
Amortization of Nuclear Fuel
    
 64,228 
    
 72,474 
   
Fuel Over/Under-Recovery, Net
    
 (2,650)
    
 2,947 
   
Change in Other Noncurrent Assets
    
 6,849 
    
 4,433 
   
Change in Other Noncurrent Liabilities
    
 42,793 
    
 12,055 
   
Changes in Certain Components of Working Capital:
            
     
Accounts Receivable, Net
    
 31,614 
    
 74,240 
     
Fuel, Materials and Supplies
    
 (8,475)
    
 26,103 
     
Accounts Payable
    
 (33,573)
    
 (76,440)
     
Accrued Taxes, Net
    
 19,642 
    
 13,775 
     
Other Current Assets
    
 (9,183)
    
 (887)
     
Other Current Liabilities
    
 (26,557)
    
 (321)
Net Cash Flows from Operating Activities
    
 248,861 
    
 336,932 
             
INVESTING ACTIVITIES
            
Construction Expenditures
    
 (137,473)
    
 (133,064)
Change in Advances to Affiliates, Net
    
 (142,752)
    
 - 
Purchases of Investment Securities
    
 (544,981)
    
 (492,162)
Sales of Investment Securities
    
 516,579 
    
 464,688 
Acquisitions of Nuclear Fuel
    
 (11,263)
    
 (93,230)
Other Investing Activities
    
 26,692 
    
 17,125 
Net Cash Flows Used for Investing Activities
    
 (293,198)
    
 (236,643)
             
FINANCING ACTIVITIES
            
Issuance of Long-term Debt – Nonaffiliated
    
 128,533 
    
 76,624 
Change in Advances from Affiliates, Net
    
 - 
    
 (18,232)
Retirement of Long-term Debt – Nonaffiliated
    
 (55,995)
    
 (116,526)
Principal Payments for Capital Lease Obligations
    
 (3,490)
    
 (4,317)
Dividends Paid on Common Stock
    
 (25,000)
    
 (37,500)
Dividends Paid on Cumulative Preferred Stock
    
 - 
    
 (170)
Other Financing Activities
    
 167 
    
 25 
Net Cash Flows from (Used for) Financing Activities
    
 44,215 
    
 (100,096)
             
Net Increase (Decrease) in Cash and Cash Equivalents
    
 (122)
    
 193 
Cash and Cash Equivalents at Beginning of Period
    
 1,020 
    
 361 
Cash and Cash Equivalents at End of Period
  
$
 898 
  
$
 554 
             
SUPPLEMENTARY INFORMATION
            
Cash Paid for Interest, Net of Capitalized Amounts
  
$
 48,565 
  
$
 47,401 
Net Cash Paid (Received) for Income Taxes
    
 (31,921)
    
 (19,847)
Noncash Acquisitions Under Capital Leases
    
 4,341 
    
 1,218 
Construction Expenditures Included in Current Liabilities at June 30,
    
 26,509 
    
 36,109 
Acquisition of Nuclear Fuel Included in Current Liabilities at June 30,
    
 14 
    
 - 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
105
 
 
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 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 146.

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



 
106
 


 

OHIO POWER COMPANY CONSOLIDATED

 
107
 
OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

CSPCo-OPCo Merger

On December 31, 2011, CSPCo merged into OPCo with OPCo being the surviving entity.  All prior reported amounts have been recast as if the merger occurred on the first day of the earliest reporting period.   All contracts and operations of CSPCo and its subsidiary are now part of OPCo.

Proposed June 2012 – May 2015 Ohio ESP

In March 2012, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing.  The SSO rates would be effective through May 2015.  The ESP will transition OPCo to an auction-based SSO for capacity and energy by June 2015.  The ESP also proposed to collect the Phase-In Recovery Rider from June 2013 through December 2018.  Further, the ESP proposed establishment of a non-bypassable Distribution Investment Rider through May 2015 to recover, with certain caps, post-August 2010 distribution investment.  The filing also seeks establishment of a new non-bypassable Retail Stability Rider (RSR) to recover lost generation revenues to provide financial certainty and stability during the ESP transition period.  The proposed RSR would be effective through May 2015.  Finally, the ESP proposed a storm damage recovery mechanism for the deferral of operation and maintenance costs above $5 million, effective January 2012.

Intervenors and the PUCO staff filed testimony in May 2012 in opposition to many aspects of OPCo’s ESP, including the proposed RSR and the two-tiered capacity pricing structure for CRES providers.  In addition, the PUCO staff’s testimony included a proposal to increase the vegetation management base used for calculating over/under recovery on incremental vegetation spend from $21 million to $39 million, which could increase future Other Operation and Maintenance expense by $18 million on an annual basis.  A decision from the PUCO is expected in August 2012.  See “Ohio Electric Security Plan Filing” section of Note 2.

Ohio Customer Choice

In OPCo’s service territory, various CRES providers are targeting retail customers by offering alternative generation service.  As a result, in comparison to the second quarter of 2011 and the first six months of 2011, OPCo lost approximately $64 million and $112 million, respectively, of gross margin.  OPCo is recovering a portion of lost margins through collection of capacity revenues from CRES providers and off-system sales.  OPCo has lost 34% of its load to CRES providers.

Ohio Capacity Rate

In March 2012, in response to OPCo’s motion for relief, the PUCO ordered that CRES providers not qualifying for the tier one capacity billing rate of $146/MW day, which is substantially below OPCo’s current capacity cost of approximately $355/MW day, will pay a tier two capacity billing rate of $255/MW day.  In July 2012, the PUCO issued an order in the capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer its incurred capacity costs not recovered from CRES providers to the extent that the total incurred capacity costs do not exceed $188.88/MW day.  The RPM price is approximately $20/MW day through May 2013.  The order stated that the PUCO would establish an appropriate recovery mechanism in the pending June 2012 – May 2015 ESP proceeding.  The PUCO postponed implementation of the order until August 8, 2012 or until an order is issued in OPCo’s pending June 2012 – May 2015 ESP proceeding, whichever is sooner.  In July 2012, OPCo requested rehearing of the PUCO order.  See “Ohio Electric Security Plan Filing” section of Note 2.

Proposed Corporate Separation and Termination of the Interconnection Agreement

In March 2012, OPCo filed an application with the PUCO for approval of the corporate separation of its generation assets including the transfer of generation assets to a nonregulated AEP subsidiary at net book value.  Additional filings at the FERC and other state commissions related to corporate separation are expected to be filed in the future.  
 
 
108
 
If all regulatory approvals are received, OPCo’s results of operations related to generation will be determined by its ability to sell power and capacity at a profit at rates determined by the prevailing market.  If OPCo is unable to sell power and capacity at a profit, it could reduce future net income and cash flows and impact financial condition.  A decision is pending from the PUCO.

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC.  It is unknown at this time whether the Interconnection Agreement 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.  Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future.  If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement 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.

Storm Damage

In late June 2012 and early July 2012, OPCo was significantly impacted by several severe storms.  In the second quarter of 2012, OPCo incurred minimal incremental operation and maintenance expenses related to the June 2012 storms.  OPCo expects to incur an estimated $100 million in total storm restoration costs in the third quarter of 2012, including an estimated $35 million in capital spending related to these storms and an estimated $65 million in incremental operation and maintenance costs.  OPCo intends to defer the majority of the incremental operation and maintenance costs and seek future recovery.  If OPCo is not ultimately permitted to recover these storm costs, it would reduce future net income and cash flows and impact financial condition.

Securitization of Regulatory Assets

OPCo plans to file, in the third quarter of 2012, an application with the PUCO requesting securitization of the Distribution Asset Recovery Rider (DARR) balance.  As of June 30, 2012, OPCo’s DARR balance was $309 million, including $145 million of unrecognized equity carrying costs.  Currently, the DARR is being recovered through 2018.  
 
Significantly Excessive Earnings Test

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off of certain pretax earnings in 2010 and a subsequent refund to customers during 2011.  In May 2011, the Industrial Energy Users-Ohio and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO’s SEET decision.  In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  Subsequent testimony and legal briefs from intervenors recommended refunds of 2010 earnings.  OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis.  The PUCO approved OPCo’s request to file the 2011 SEET on July 31, 2012 or one month after the PUCO issues an order on the 2010 SEET, whichever is later.  Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo.  See “Ohio Electric Security Plan Filing” section of Note 2.

Ohio Distribution Base Rate Case

In December 2011, a stipulation was approved by the PUCO which provided for no change in distribution rates and a new rider for a $15 million annual credit to residential ratepayers due principally to the inclusion of the rate base distribution investment in the Distribution Investment Rider (DIR) as approved by the modified stipulation in the ESP proceeding.  Because the February 2012 PUCO order rejected the ESP modified stipulation, collection of the DIR terminated.  In March 2012, OPCo filed an application with the PUCO to approve an ESP for the period June 2012 through May 2015, which includes a request for a new DIR.  A decision in the June 2012 – May 2015 ESP proceeding is expected in August 2012.  In March 2012, the PUCO issued an order clarifying that OPCo has the right to file a new distribution base rate case.  See “2011 Ohio Distribution Base Rate Case” section of Note 2.

 
109
 
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 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report.  Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 146.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 201 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,
 
2012 
  
2011 
  
2012 
  
2011 
     
(in millions of KWHs)
Retail:
                      
 
Residential
  
 3,002 
    
 3,141 
    
 6,881 
    
 7,592 
 
Commercial
  
 3,582 
    
 3,512 
    
 6,818 
    
 6,901 
 
Industrial
  
 4,799 
    
 4,815 
    
 9,520 
    
 9,355 
 
Miscellaneous
  
 27 
    
 28 
    
 58 
    
 63 
Total Retail (a)
  
 11,410 
    
 11,496 
    
 23,277 
    
 23,911 
                       
Wholesale
  
 2,798 
    
 2,911 
    
 5,304 
    
 5,682 
                       
Total KWHs
  
 14,208 
    
 14,407 
    
 28,581 
    
 29,593 
                           
(a)
Represents energy delivered to distribution customers.

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,
   
2012 
  
2011 
  
2012 
  
2011 
   
(in degree days)
Actual - Heating (a)
  
 146 
    
 161 
    
 1,543 
    
 2,234 
Normal - Heating (b)
  
 195 
    
 198 
    
 2,112 
    
 2,101 
                         
Actual - Cooling (c)
  
 401 
    
 323 
    
 428 
    
 324 
Normal - Cooling (b)
  
 270 
    
 266 
    
 273 
    
 268 
                         
(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.
 
 
 
110
 
 
Second Quarter of 2012 Compared to Second Quarter of 2011
 
Reconciliation of Second Quarter of 2011 to Second Quarter of 2012
Net Income
(in millions)
               
Second Quarter of 2011
        
$
 142 
               
Changes in Gross Margin:
            
Retail Margins
          
 (98)
Off-system Sales
          
 12 
Transmission Revenues
          
 10 
Other Revenues
          
 10 
Total Change in Gross Margin
          
 (66)
             
Changes in Expenses and Other:
            
Other Operation and Maintenance
          
 25 
Depreciation and Amortization
          
 (7)
Taxes Other Than Income Taxes
          
 (3)
Carrying Costs Income
          
 (5)
Other Income
          
 (1)
Interest Expense
          
 3 
Total Change in Expenses and Other
          
 12 
               
Income Tax Expense
          
 13 
               
Second Quarter of 2012
        
$
 101 

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 electricity were as follows:

 
·
Retail Margins decreased $98 million primarily due to the following:
   
·
A $70 million decrease attributable to customers switching to alternative CRES providers.  This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
   
·
A $48 million decrease in capacity settlement revenues under the Interconnection Agreement.  This decrease was primarily as a result of a mild winter in 2012 and its impact on APCo’s winter peak, APCo’s completion of the Dresden Plant in January 2012 and the removal of Sporn Unit 5 from the Interconnection Agreement in the third quarter of 2011.
   
·
A $13 million net decrease in regulated revenue primarily due to the elimination of POLR charges effective June 2011, resulting from an October 2011 PUCO remand order.
   
These decreases were partially offset by:
   
·
A $35 million increase due to the partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
   
·
A $9 million increase in weather-related usage primarily due to a 24% increase in cooling degree days.
 
·
Margins from Off-system Sales increased $12 million primarily due to higher PJM capacity revenues, partially offset by lower physical sales volumes and lower trading and marketing margins.
 
·
Transmission Revenues increased $10 million primarily due to increased transmission revenues for customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers partially offsets lost revenues included in Retail Margins above.
 
·
Other Revenues increased $10 million primarily due to sales to Buckeye Power, Inc. to provide backup energy under the Cardinal Station Agreement and increased revenues from Cook Coal Terminal.

 
111
 
Expenses and Other and Income Tax Expense changed between years as follows:

 
·
Other Operation and Maintenance expenses decreased $25 million primarily due to the following:
   
·
A $28 million decrease in plant maintenance expenses at various plants.
   
·
A $4 million reserve recorded in second quarter of 2011 as a result of a legal proceeding.
   
·
A $3 million decrease in employee-related expenses.
   
These decreases were partially offset by:
   
·
A $7 million increase in advertising expenses.
   
·
A $3 million increase due to expenses related to the 2012 sustainable cost reductions.
 
·
Depreciation and Amortization expenses increased $7 million primarily due to the following:
   
·
An $18 million increase due to shortened depreciable lives for certain generating plants effective December 2011.
   
·
A $2 million increase in amortization of the Deferred Asset Recovery Rider assets as approved by the PUCO in the 2011 Ohio Distribution Base Rate Case.
   
These increases were partially offset by:
   
·
A $10 million decrease due to an amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
   
·
A $5 million decrease in depreciation due to the third quarter 2011 plant impairment of Sporn Unit 5.
 
·
Carrying Costs Income decreased $5 million primarily due to a reduction in debt carrying charges associated with the 2008 coal contract settlement for the period January 2009 through March 2012 as ordered by the PUCO in April 2012 related to the 2009 FAC audit.
 
·
Income Tax Expense decreased $13 million primarily due to a decrease in pretax book income partially offset by other book/tax differences which are accounted for on a flow-through basis.
 
 
 
112
 
 
Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011
 
Reconciliation of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2012
Net Income
(in millions)
               
Six Months Ended June 30, 2011
        
$
 308 
               
Changes in Gross Margin:
            
Retail Margins
          
 (201)
Off-system Sales
          
 19 
Transmission Revenues
          
 17 
Other Revenues
          
 17 
Total Change in Gross Margin
          
 (148)
             
Changes in Expenses and Other:
            
Other Operation and Maintenance
          
 78 
Depreciation and Amortization
          
 (8)
Taxes Other Than Income Taxes
          
 (3)
Carrying Costs Income
          
 (13)
Interest Expense
          
 6 
Total Change in Expenses and Other
          
 60 
               
Income Tax Expense
          
 32 
               
Six Months Ended June 30, 2012
        
$
 252 

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 electricity were as follows:

 
·
Retail Margins decreased $201 million primarily due to the following:
   
·
A $124 million decrease attributable to customers switching to alternative CRES providers.  This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
   
·
An $88 million decrease in capacity settlement revenues under the Interconnection Agreement.  This decrease was primarily as a result of a mild winter in 2012 and its impact on APCo’s winter peak, APCo’s completion of the Dresden Plant in January 2012 and the removal of Sporn Unit 5 from the Interconnection Agreement in the third quarter of 2011.
   
·
A $17 million net decrease in regulated revenue primarily due to the elimination of POLR charges effective June 2011, resulting from an October 2011 PUCO remand order.
   
·
A $13 million decrease in weather-related usage primarily due to a 31% decrease in heating degree days.
   
These decreases were partially offset by:
   
·
A $35 million increase due to the second quarter 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
 
·
Margins from Off-system Sales increased $19 million primarily due to higher PJM capacity revenues, partially offset by lower physical sales volumes and lower trading and marketing margins.
 
·
Transmission Revenues increased $17 million primarily due to increased transmission revenues for customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers offsets lost revenues included in Retail Margins above.
 
·
Other Revenues increased $17 million primarily due to higher sales to Buckeye Power, Inc. to provide backup energy under the Cardinal Station Agreement and increased revenues from Cook Coal Terminal.

 
113
 
Expenses and Other and Income Tax Expense changed between years as follows:

 
·
Other Operation and Maintenance expenses decreased $78 million primarily due to the following:
   
·
A $40 million decrease in plant maintenance expenses at various plants.
   
·
A $35 million decrease due to the first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of the Ohio modified stipulation.
   
·
A $10 million decrease in employee-related expenses.
   
These decreases were partially offset by:
   
·
An $11 million gain from the sale of land in January 2011.
   
·
A $7 million increase in advertising expenses.
   
·
A $3 million increase due to expenses related to the 2012 sustainable cost reductions.
 
·
Depreciation and Amortization expenses increased $8 million primarily due to the following:
   
·
A $32 million increase due to shortened depreciable lives for certain generating plants effective December 2011.
   
·
A $5 million increase in amortization of the Deferred Asset Recovery Rider assets as approved by the PUCO in the 2011 Ohio Distribution Base Rate Case.
   
These increases were partially offset by:
   
·
A $19 million decrease due to an amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
   
·
A $10 million decrease in depreciation due to the third quarter 2011 plant impairment of Sporn Unit 5.
 
·
Carrying Costs Income decreased $13 million primarily due to the following:
   
·
A $5 million reduction in debt carrying charges associated with the 2008 coal contract settlement for the period January 2009 through March 2012 as ordered by the PUCO in April 2012 related to the 2009 FAC audit.
   
·
The collection of $3 million in carrying costs in first quarter 2012 on phase-in FAC deferrals.
   
·
A $3 million decrease due to line extension carrying charges recorded in 2011.
 
·
Interest Expense decreased $6 million as a result of the reversal of capitalized interest on ESP Projects, an increase in the debt component of AFUDC as a result of new construction and the reversal of interest accruals related to federal tax reserve positions.
 
·
Income Tax Expense decreased $32 million primarily due to a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2011 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 Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of accounting pronouncements.
 
 
114
 
 
OHIO POWER COMPANY CONSOLIDATED
  
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
  
For the Three and Six Months Ended June 30, 2012 and 2011
  
(in thousands)
  
(Unaudited)
  
   
   
Three Months Ended
    
Six Months Ended
  
   
2012
    
2011
    
2012
    
2011
  
REVENUES
                        
Electric Generation, Transmission and Distribution
   $ 929,487     $ 1,041,528     $ 1,970,318     $ 2,171,705  
Sales to AEP Affiliates
     172,561       235,625       354,318       488,159  
Other Revenues - Affiliated
     7,979       4,507       17,090       11,525  
Other Revenues - Nonaffiliated
     3,723       3,898       9,247       8,359  
TOTAL REVENUES
     1,113,750       1,285,558       2,350,973       2,679,748  
                                 
EXPENSES
                                
Fuel and Other Consumables Used for Electric Generation
     298,294       340,733       668,287       748,129  
Purchased Electricity for Resale
     52,104       68,983       110,238       137,397  
Purchased Electricity from AEP Affiliates
     81,818       127,894       170,501       244,345  
Other Operation
     162,086       159,553       292,428       329,952  
Maintenance
     74,015       102,030       154,619       195,442  
Depreciation and Amortization
     137,009       129,698       271,439       263,110  
Taxes Other Than Income Taxes
     98,420       95,133       203,838       200,443  
TOTAL EXPENSES
     903,746       1,024,024       1,871,350       2,118,818  
                                 
OPERATING INCOME
     210,004       261,534       479,623       560,930  
                                 
Other Income (Expense):
                                
Interest Income
     345       437       1,443       895  
Carrying Costs Income
     4,511       9,847       7,269       20,578  
Allowance for Equity Funds Used During Construction
     915       1,508       2,038       2,711  
Interest Expense
     (53,147 )     (56,631 )     (107,408 )     (113,651 )
                                 
INCOME BEFORE INCOME TAX EXPENSE
     162,628       216,695       382,965       471,463  
                                 
Income Tax Expense
     61,205       74,501       130,712       163,299  
                                 
NET INCOME
     101,423       142,194       252,253       308,164  
                                 
Preferred Stock Dividend Requirements Including
                                
Capital Stock Expense
     -       208       -       416  
                                 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
   $ 101,423     $ 141,986     $ 252,253     $ 307,748  
                                 
The common stock of OPCo is wholly-owned by AEP.
                                
                                 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
  
 
 
 
115
 

 
OHIO POWER COMPANY CONSOLIDATED
  
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
  
For the Three and Six Months Ended June 30, 2012 and 2011
  
(in thousands)
  
(Unaudited)
  
                   
   
Three Months Ended
  
Six Months Ended
  
   
2012
  
2011
  
2012
  
2011
  
Net Income
   $ 101,423   $ 142,194   $ 252,253   $ 308,164  
                           
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                          
Cash Flow Hedges, Net of Tax of $91 and $122 for the Three Months Ended
                          
June 30, 2012 and 2011, Respectively, and $846 and $280 for the Six
                          
Months Ended June 30, 2012 and 2011, Respectively
     170     228     (1,571 )   521  
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,745
                          
and $1,422 for the Three Months Ended June 30, 2012 and 2011,
                          
Respectively, and $3,490 and $2,844 for the Six Months Ended June 30,
                          
2012 and 2011, Respectively
     3,240     2,640     6,481     5,281  
                           
TOTAL OTHER COMPREHENSIVE INCOME
     3,410     2,868     4,910     5,802  
                           
TOTAL COMPREHENSIVE INCOME
   $ 104,833   $ 145,062   $ 257,163   $ 313,966  
                           
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
  
 
 
 
116
 
 
 
OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)
           
                     
Accumulated
    
                     
Other
    
   
Common
  
Paid-in
  
Retained
  
Comprehensive
    
         
Stock
  
Capital
  
Earnings
  
Income (Loss)
  
Total
TOTAL COMMON SHAREHOLDER'S
                              
   
EQUITY – DECEMBER 31, 2010
  
$
 321,201 
  
$
 1,744,991 
  
$
 2,768,602 
  
$
 (180,155)
  
$
 4,654,639 
                               
Common Stock Dividends
                
 (325,000)
          
 (325,000)
Preferred Stock Dividends
                
 (366)
          
 (366)
Capital Stock Expense
          
 50 
    
 (50)
          
 - 
Subtotal – Common Shareholder's Equity
                            
 4,329,273 
                               
Net Income
                
 308,164 
          
 308,164 
Other Comprehensive Income
                      
 5,802 
    
 5,802 
TOTAL COMMON SHAREHOLDER'S
                              
   
EQUITY –  JUNE 30, 2011
  
$
 321,201 
  
$
 1,745,041 
  
$
 2,751,350 
  
$
 (174,353)
  
$
 4,643,239 
                               
TOTAL COMMON SHAREHOLDER'S
                              
   
EQUITY – DECEMBER 31, 2011
  
$
 321,201 
  
$
 1,744,099 
  
$
 2,582,600 
  
$
 (197,722)
  
$
 4,450,178 
                               
Common Stock Dividends
                
 (150,000)
          
 (150,000)
Subtotal – Common Shareholder's Equity
                            
 4,300,178 
                               
Net Income
                
 252,253 
          
 252,253 
Other Comprehensive Income
                      
 4,910 
    
 4,910 
TOTAL COMMON SHAREHOLDER'S
                              
   
EQUITY –  JUNE 30, 2012
  
$
 321,201 
  
$
 1,744,099 
  
$
 2,684,853 
  
$
 (192,812)
  
$
 4,557,341 
                               
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
 
117
 
 
 
OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)
 
   
2012 
  
2011 
CURRENT ASSETS
            
Cash and Cash Equivalents
  
$
 2,366 
  
$
 2,095 
Advances to Affiliates
    
 32,671 
    
 219,458 
Accounts Receivable:
            
 
Customers
    
 116,264 
    
 146,432 
 
Affiliated Companies
    
 146,434 
    
 162,830 
 
Accrued Unbilled Revenues
    
 13,865 
    
 19,012 
 
Miscellaneous
    
 5,030 
    
 16,994 
 
Allowance for Uncollectible Accounts
    
 (3,712)
    
 (3,563)
   
Total Accounts Receivable
    
 277,881 
    
 341,705 
Fuel
    
 344,642 
    
 262,886 
Materials and Supplies
    
 191,005 
    
 201,325 
Risk Management Assets
    
 62,962 
    
 54,293 
Accrued Tax Benefits
    
 6,643 
    
 11,975 
Prepayments and Other Current Assets
    
 29,430 
    
 41,560 
TOTAL CURRENT ASSETS
    
 947,600 
    
 1,135,297 
             
PROPERTY, PLANT AND EQUIPMENT
            
Electric:
            
 
Generation
    
 9,552,733 
    
 9,502,614 
 
Transmission
    
 1,971,788 
    
 1,948,329 
 
Distribution
    
 3,631,335 
    
 3,545,574 
Other Property, Plant and Equipment
    
 568,702 
    
 546,642 
Construction Work in Progress
    
 346,531 
    
 354,465 
Total Property, Plant and Equipment
    
 16,071,089 
    
 15,897,624 
Accumulated Depreciation and Amortization
    
 5,764,534 
    
 5,742,561 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    
 10,306,555 
    
 10,155,063 
             
OTHER NONCURRENT ASSETS
            
Regulatory Assets
    
 1,405,104 
    
 1,370,504 
Long-term Risk Management Assets
    
 66,290 
    
 53,614 
Deferred Charges and Other Noncurrent Assets
    
 193,784 
    
 309,775 
TOTAL OTHER NONCURRENT ASSETS
    
 1,665,178 
    
 1,733,893 
             
TOTAL ASSETS
  
$
 12,919,333 
  
$
 13,024,253 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
118
 
OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2012 and December 31, 2011
(Unaudited)
 
   
2012 
  
2011 
     
(in thousands)
CURRENT LIABILITIES
            
Accounts Payable:
            
 
General
  
$
 224,892 
  
$
 293,730 
 
Affiliated Companies
    
 97,248 
    
 183,898 
Long-term Debt Due Within One Year – Nonaffiliated
    
 606,000 
    
 244,500 
Risk Management Liabilities
    
 35,141 
    
 36,561 
Accrued Taxes
    
 327,397 
    
 450,570 
Accrued Interest
    
 65,405 
    
 66,441 
Other Current Liabilities
    
 240,361 
    
 238,275 
TOTAL CURRENT LIABILITIES
    
 1,596,444 
    
 1,513,975 
             
NONCURRENT LIABILITIES
            
Long-term Debt – Nonaffiliated
    
 3,054,044 
    
 3,609,648 
Long-term Debt – Affiliated
    
 200,000 
    
 200,000 
Long-term Risk Management Liabilities
    
 33,753 
    
 17,890 
Deferred Income Taxes
    
 2,323,655 
    
 2,245,380 
Regulatory Liabilities and Deferred Investment Tax Credits
    
 507,454 
    
 301,124 
Employee Benefits and Pension Obligations
    
 318,506 
    
 335,029 
Deferred Credits and Other Noncurrent Liabilities
    
 328,136 
    
 351,029 
TOTAL NONCURRENT LIABILITIES
    
 6,765,548 
    
 7,060,100 
             
TOTAL LIABILITIES
    
 8,361,992 
    
 8,574,075 
                 
Rate Matters (Note 2)
            
Commitments and Contingencies (Note 3)
            
             
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
    
 1,744,099 
    
 1,744,099 
Retained Earnings
    
 2,684,853 
    
 2,582,600 
Accumulated Other Comprehensive Income (Loss)
    
 (192,812)
    
 (197,722)
TOTAL COMMON SHAREHOLDER’S EQUITY
    
 4,557,341 
    
 4,450,178 
             
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
  
$
 12,919,333 
  
$
 13,024,253 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
 
119
 
 
OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)
 
   
2012 
  
2011 
OPERATING ACTIVITIES
            
Net Income
  
$
 252,253 
  
$
 308,164 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
            
   
Depreciation and Amortization
    
 271,439 
    
 263,110 
   
Deferred Income Taxes
    
 82,961 
    
 115,726 
   
Carrying Costs Income
    
 (7,269)
    
 (20,578)
   
Allowance for Equity Funds Used During Construction
    
 (2,038)
    
 (2,711)
   
Mark-to-Market of Risk Management Contracts
    
 (8,328)
    
 9,491 
   
Property Taxes
    
 109,892 
    
 108,074 
   
Fuel Over/Under-Recovery, Net
    
 (19,433)
    
 (50,113)
   
Change in Other Noncurrent Assets
    
 (20,063)
    
 (54,116)
   
Change in Other Noncurrent Liabilities
    
 416 
    
 24,932 
   
Changes in Certain Components of Working Capital:
            
     
Accounts Receivable, Net
    
 64,404 
    
 114,701 
     
Fuel, Materials and Supplies
    
 (70,666)
    
 69,406 
     
Accounts Payable
    
 (134,823)
    
 (62,574)
     
Accrued Taxes, Net
    
 (115,596)
    
 (156,417)
     
Other Current Assets
    
 7,982 
    
 3,700 
     
Other Current Liabilities
    
 (13,884)
    
 (30,536)
Net Cash Flows from Operating Activities
    
 397,247 
    
 640,259 
             
INVESTING ACTIVITIES
            
Construction Expenditures
    
 (246,657)
    
 (201,512)
Change in Advances to Affiliates, Net
    
 186,787 
    
 (53,586)
Acquisitions of Assets
    
 (48)
    
 (1,714)
Proceeds from Sales of Assets
    
 5,475 
    
 45,129 
Other Investing Activities
    
 6,753 
    
 19,495 
Net Cash Flows Used for Investing Activities
    
 (47,690)
    
 (192,188)
             
FINANCING ACTIVITIES
            
Issuance of Long-term Debt – Nonaffiliated
    
 - 
    
 49,768 
Retirement of Long-term Debt – Nonaffiliated
    
 (194,500)
    
 (165,000)
Retirement of Cumulative Preferred Stock
    
 - 
    
 (1)
Principal Payments for Capital Lease Obligations
    
 (4,920)
    
 (5,852)
Dividends Paid on Common Stock
    
 (150,000)
    
 (325,000)
Dividends Paid on Cumulative Preferred Stock
    
 - 
    
 (366)
Other Financing Activities
    
 134 
    
 (122)
Net Cash Flows Used for Financing Activities
    
 (349,286)
    
 (446,573)
             
Net Increase in Cash and Cash Equivalents
    
 271 
    
 1,498 
Cash and Cash Equivalents at Beginning of Period
    
 2,095 
    
 949 
Cash and Cash Equivalents at End of Period
  
$
 2,366 
  
$
 2,447 
             
SUPPLEMENTARY INFORMATION
            
Cash Paid for Interest, Net of Capitalized Amounts
  
$
 107,216 
  
$
 109,135 
Net Cash Paid for Income Taxes
    
 15,019 
    
 52,476 
Noncash Acquisitions Under Capital Leases
    
 4,239 
    
 1,002 
Government Grants Included in Accounts Receivable at June 30,
    
 1,094 
    
 2,000 
Construction Expenditures Included in Current Liabilities at June 30,
    
 41,873 
    
 26,719 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
120
 
OHIO POWER COMPANY CONSOLIDATED
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to OPCo’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 OPCo.  The footnotes begin on page 146.

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



 
121
 


 

PUBLIC SERVICE COMPANY OF OKLAHOMA
 
 
122
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

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 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report.  Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 146.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 201 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,
 
2012 
  
2011 
  
2012 
  
2011 
     
(in millions of KWHs)
Retail:
                      
 
Residential
  
 1,542 
    
 1,537 
    
 2,879 
    
 3,077 
 
Commercial
  
 1,373 
    
 1,389 
    
 2,474 
    
 2,520 
 
Industrial
  
 1,298 
    
 1,243 
    
 2,491 
    
 2,366 
 
Miscellaneous
  
 341 
    
 339 
    
 641 
    
 617 
Total Retail (a)
  
 4,554 
    
 4,508 
    
 8,485 
    
 8,580 
                       
Wholesale
  
 394 
    
 317 
    
 939 
    
 552 
                       
Total KWHs
  
 4,948 
    
 4,825 
    
 9,424 
    
 9,132 
                           
(a)
Represents energy delivered to distribution customers.

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,
     
2012 
  
2011 
  
2012 
  
2011 
     
(in degree days)
 
Actual - Heating (a)
  
 - 
    
 19 
    
 676 
    
 1,276 
 
Normal - Heating (b)
  
 41 
    
 42 
    
 1,107 
    
 1,100 
                           
 
Actual - Cooling (c)
  
 871 
    
 912 
    
 935 
    
 945 
 
Normal - Cooling (b)
  
 635 
    
 624 
    
 648 
    
 637 
                           
 
(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.
 
 
 
 
123
 
Second Quarter of 2012 Compared to Second Quarter of 2011
 
Reconciliation of Second Quarter of 2011 to Second Quarter of 2012
Net Income
(in millions)
                 
Second Quarter of 2011
        
$
 32 
                 
Changes in Gross Margin:
            
Retail Margins (a)
          
 4 
Total Change in Gross Margin
          
 4 
             
Changes in Expenses and Other:
            
Depreciation and Amortization
          
 1 
Other Income
          
 (1)
Total Change in Expenses and Other
          
 - 
                 
Income Tax Expense
          
 (1)
                 
Second Quarter of 2012
        
$
 35 
                 
(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 electricity were as follows:

 
·
Retail Margins increased $4 million primarily due to the following:
   
·
A $6 million increase primarily due to higher margins from the residential and commercial classes.
   
·
A $2 million increase primarily due to revenue increases from rate riders.  This increase in retail margins has corresponding increases to riders/trackers recognized in other expense items.
   
These increases were partially offset by:
   
·
A $4 million decrease in weather-related usage primarily due to a 4% decrease in cooling degree days.
 
 
 
124
 
Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011
 
Reconciliation of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2012
Net Income
(in millions)
                 
Six Months Ended June 30, 2011
        
$
 47 
                 
Changes in Gross Margin:
            
Retail Margins (a)
          
 11 
Transmission Revenues
          
 (2)
Total Change in Gross Margin
          
 9 
             
Changes in Expenses and Other:
            
Other Operation and Maintenance
          
 (10)
Depreciation and Amortization
          
 1 
Taxes Other Than Income Taxes
          
 (1)
Interest Expense
          
 2 
Total Change in Expenses and Other
          
 (8)
                 
Six Months Ended June 30, 2012
        
$
 48 
                 
(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 electricity were as follows:

 
·
Retail Margins increased $11 million primarily due to the following:
   
·
A $13 million increase primarily due to higher margins from the residential and commercial classes.
   
·
A $6 million increase primarily due to revenue increases from rate riders.  This increase in retail margins has corresponding increases to riders/trackers recognized in other expense items below.
   
These increases were partially offset by:
   
·
A $9 million decrease in weather-related usage primarily due to a decrease in heating and cooling degree days.

Expenses and Other changed between years as follows:

 
·
Other Operation and Maintenance expenses increased $10 million primarily due to the following:
   
·
A $7 million increase in transmission expenses primarily due to increased SPP transmission services.
   
·
A $6 million increase in plant expenses primarily due to the 2011 deferral of generation maintenance expenses as a result of an order in PSO’s base rate case and an increase in generation plant maintenance.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2011 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 Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of accounting pronouncements.
 
 
 
125
 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
  
CONDENSED STATEMENTS OF INCOME
  
For the Three and Six Months Ended June 30, 2012 and 2011
  
(in thousands)
  
(Unaudited)
  
                         
   
Three Months Ended
    
Six Months Ended
  
   
2012
    
2011
    
2012
    
2011
  
REVENUES
                        
Electric Generation, Transmission and Distribution
   $ 311,310     $ 322,028     $ 603,832     $ 606,615  
Sales to AEP Affiliates
     5,407       5,785       12,512       8,581  
Other Revenues
     594       775       1,498       1,395  
TOTAL REVENUES
     317,311       328,588       617,842       616,591  
                                 
EXPENSES
                                
Fuel and Other Consumables Used for Electric Generation
     91,126       100,796       216,551       192,544  
Purchased Electricity for Resale
     44,822       46,018       70,264       87,197  
Purchased Electricity from AEP Affiliates
     4,260       9,111       10,458       25,722  
Other Operation
     48,880       48,736       95,859       93,140  
Maintenance
     24,853       25,152       53,178       45,873  
Depreciation and Amortization
     23,390       24,096       46,923       47,959  
Taxes Other Than Income Taxes
     10,681       10,494       21,820       21,090  
TOTAL EXPENSES
     248,012       264,403       515,053       513,525  
                                 
OPERATING INCOME
     69,299       64,185       102,789       103,066  
                                 
Other Income (Expense):
                                
Interest Income
     97       28       1,032       80  
Carrying Costs Income
     529       1,876       1,142       2,523  
Allowance for Equity Funds Used During Construction
     468       284       890       650  
Interest Expense
     (13,766 )     (14,258 )     (28,477 )     (30,196 )
                                 
INCOME BEFORE INCOME TAX EXPENSE
     56,627       52,115       77,376       76,123  
                                 
Income Tax Expense
     21,416       20,555       29,517       29,174  
                                 
NET INCOME
     35,211       31,560       47,859       46,949  
                                 
Preferred Stock Dividend Requirements
     -       49       -       98  
                                 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
   $ 35,211     $ 31,511     $ 47,859     $ 46,851  
                                 
The common stock of PSO is wholly-owned by AEP.
                                
                                 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
  
 
 
 
126
 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
  
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
  
For the Three and Six Months Ended June 30, 2012 and 2011
  
(in thousands)
  
(Unaudited)
  
                   
   
Three Months Ended
  
Six Months Ended
  
   
2012
  
2011
  
2012
  
2011
  
Net Income
   $ 35,211   $ 31,560   $ 47,859   $ 46,949  
                           
OTHER COMPREHENSIVE LOSS, NET OF TAXES
                          
Cash Flow Hedges, Net of Tax of $193 and $168 for the Three Months Ended
                          
June 30, 2012 and 2011, Respectively, and $222 and $407 for the Six
                          
Months Ended June 30, 2012 and 2011, Respectively
     (359 )   (313 )   (412 )   (756 )
                           
TOTAL COMPREHENSIVE INCOME
   $ 34,852   $ 31,247   $ 47,447   $ 46,193  
                           
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
  
 
 
 
127
 

 
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)
 
                     
Accumulated
    
                     
Other
    
   
Common
  
Paid-in
  
Retained
  
Comprehensive
    
         
Stock
  
Capital
  
Earnings
  
Income (Loss)
  
Total
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 
                               
Net Income
                
 46,949 
          
 46,949 
Other Comprehensive Loss
                      
 (756)
    
 (756)
TOTAL COMMON SHAREHOLDER'S
                              
 
EQUITY – JUNE 30, 2011
  
$
 157,230 
  
$
 364,307 
  
$
 326,792 
  
$
 7,738 
  
$
 856,067 
                               
TOTAL COMMON SHAREHOLDER'S
                              
 
EQUITY – DECEMBER 31, 2011
  
$
 157,230 
  
$
 364,037 
  
$
 364,389 
  
$
 7,149 
  
$
 892,805 
                               
Common Stock Dividends
                
 (30,000)
          
 (30,000)
Subtotal – Common Shareholder's Equity
                            
 862,805 
                               
Net Income
                
 47,859 
          
 47,859 
Other Comprehensive Loss
                      
 (412)
    
 (412)
TOTAL COMMON SHAREHOLDER'S
                              
 
EQUITY – JUNE 30, 2012
  
$
 157,230 
  
$
 364,037 
  
$
 382,248 
  
$
 6,737 
  
$
 910,252 
                               
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
 
128
 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
June 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)
 
   
2012 
  
2011 
CURRENT ASSETS
            
Cash and Cash Equivalents
  
$
 1,233 
  
$
 1,413 
Advances to Affiliates
    
 120,424 
    
 39,876 
Accounts Receivable:
            
 
Customers
    
 39,426 
    
 39,977 
 
Affiliated Companies
    
 22,922 
    
 23,079 
 
Miscellaneous
    
 7,408 
    
 8,993 
 
Allowance for Uncollectible Accounts
    
 (951)
    
 (777)
   
Total Accounts Receivable
    
 68,805 
    
 71,272 
Fuel
    
 18,311 
    
 20,854 
Materials and Supplies
    
 50,409 
    
 50,347 
Risk Management Assets
    
 592 
    
 565 
Deferred Income Tax Benefits
    
 10,439 
    
 7,013 
Accrued Tax Benefits
    
 5,508 
    
 6,733 
Regulatory Asset for Under-Recovered Fuel Costs
    
 - 
    
 4,313 
Prepayments and Other Current Assets
    
 5,248 
    
 6,440 
TOTAL CURRENT ASSETS
    
 280,969 
    
 208,826 
             
PROPERTY, PLANT AND EQUIPMENT
            
Electric:
            
 
Generation
    
 1,326,618 
    
 1,317,948 
 
Transmission
    
 701,121 
    
 692,644 
 
Distribution
    
 1,812,061 
    
 1,762,110 
Other Property, Plant and Equipment
    
 222,958 
    
 214,626 
Construction Work in Progress
    
 59,916 
    
 70,371 
Total Property, Plant and Equipment
    
 4,122,674 
    
 4,057,699 
Accumulated Depreciation and Amortization
    
 1,266,744 
    
 1,266,816 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    
 2,855,930 
    
 2,790,883 
             
OTHER NONCURRENT ASSETS
            
Regulatory Assets
    
 254,017 
    
 266,545 
Long-term Risk Management Assets
    
 131 
    
 314 
Deferred Charges and Other Noncurrent Assets
    
 32,220 
    
 13,536 
TOTAL OTHER NONCURRENT ASSETS
    
 286,368 
    
 280,395 
             
TOTAL ASSETS
  
$
 3,423,267 
  
$
 3,280,104 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
 
129
 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2012 and December 31, 2011
(Unaudited)
             
   
2012 
  
2011 
     
(in thousands)
CURRENT LIABILITIES
            
Accounts Payable:
            
 
General
  
$
 71,070 
  
$
 76,607 
 
Affiliated Companies
    
 49,294 
    
 45,029 
Long-term Debt Due Within One Year – Nonaffiliated
    
 758 
    
 311 
Risk Management Liabilities
    
 4,651 
    
 1,280 
Customer Deposits
    
 46,818 
    
 47,493 
Accrued Taxes
    
 53,566 
    
 21,660 
Accrued Interest
    
 12,285 
    
 12,637 
Regulatory Liability for Over-Recovered Fuel Costs
    
 71,785 
    
 - 
Other Current Liabilities
    
 41,277 
    
 43,586 
TOTAL CURRENT LIABILITIES
    
 351,504 
    
 248,603 
             
NONCURRENT LIABILITIES
            
Long-term Debt – Nonaffiliated
    
 949,139 
    
 947,053 
Long-term Risk Management Liabilities
    
 2,490 
    
 1,330 
Deferred Income Taxes
    
 740,600 
    
 726,463 
Regulatory Liabilities and Deferred Investment Tax Credits
    
 343,762 
    
 334,812 
Employee Benefits and Pension Obligations
    
 82,625 
    
 84,548 
Deferred Credits and Other Noncurrent Liabilities
    
 42,895 
    
 44,490 
TOTAL NONCURRENT LIABILITIES
    
 2,161,511 
    
 2,138,696 
             
TOTAL LIABILITIES
    
 2,513,015 
    
 2,387,299 
             
             
Rate Matters (Note 2)
          
 
Commitments and Contingencies (Note 3)
    
 
    
 
             
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
    
 364,037 
    
 364,037 
Retained Earnings
    
 382,248 
    
 364,389 
Accumulated Other Comprehensive Income (Loss)
    
 6,737 
    
 7,149 
TOTAL COMMON SHAREHOLDER’S EQUITY
    
 910,252 
    
 892,805 
             
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
  
$
 3,423,267 
  
$
 3,280,104 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
 
130
 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)
 
   
2012 
  
2011 
OPERATING ACTIVITIES
            
Net Income
  
$
 47,859 
  
$
 46,949 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating
            
 
Activities:
            
   
Depreciation and Amortization
    
 46,923 
    
 47,959 
   
Deferred Income Taxes
    
 15,275 
    
 33,821 
   
Carrying Costs Income
    
 (1,142)
    
 (2,523)
   
Allowance for Equity Funds Used During Construction
    
 (890)
    
 (650)
   
Mark-to-Market of Risk Management Contracts
    
 4,652 
    
 (292)
   
Property Taxes
    
 (19,347)
    
 (18,742)
   
Fuel Over/Under-Recovery, Net
    
 76,098 
    
 (55)
   
Change in Other Noncurrent Assets
    
 1,043 
    
 8,705 
   
Change in Other Noncurrent Liabilities
    
 (5,409)
    
 21,377 
   
Changes in Certain Components of Working Capital:
            
     
Accounts Receivable, Net
    
 2,560 
    
 32,603 
     
Fuel, Materials and Supplies
    
 2,481 
    
 (3,744)
     
Accounts Payable
    
 (3,263)
    
 29,830 
     
Accrued Taxes, Net
    
 32,771 
    
 16,468 
     
Other Current Assets
    
 919 
    
 (3,070)
     
Other Current Liabilities
    
 (3,987)
    
 10,048 
Net Cash Flows from Operating Activities
    
 196,543 
    
 218,684 
             
INVESTING ACTIVITIES
            
Construction Expenditures
    
 (102,354)
    
 (65,343)
Change in Advances to Affiliates, Net
    
 (80,548)
    
 (110)
Other Investing Activities
    
 413 
    
 760 
Net Cash Flows Used for Investing Activities
    
 (182,489)
    
 (64,693)
             
FINANCING ACTIVITIES
            
Issuance of Long-term Debt – Nonaffiliated
    
 2,395 
    
 247,554 
Change in Advances from Affiliates, Net
    
 - 
    
 (91,382)
Retirement of Long-term Debt – Nonaffiliated
    
 (32)
    
 (275,000)
Principal Payments for Capital Lease Obligations
    
 (1,704)
    
 (2,068)
Dividends Paid on Common Stock
    
 (15,000)
    
 (32,500)
Dividends Paid on Cumulative Preferred Stock
    
 - 
    
 (98)
Other Financing Activities
    
 107 
    
 6 
Net Cash Flows Used for Financing Activities
    
 (14,234)
    
 (153,488)
             
Net Increase (Decrease) in Cash and Cash Equivalents
    
 (180)
    
 503 
Cash and Cash Equivalents at Beginning of Period
    
 1,413 
    
 470 
Cash and Cash Equivalents at End of Period
  
$
 1,233 
  
$
 973 
             
SUPPLEMENTARY INFORMATION
            
Cash Paid for Interest, Net of Capitalized Amounts
  
$
 26,581 
  
$
 12,293 
Net Cash Paid for Income Taxes
    
 5,992 
    
 383 
Noncash Acquisitions Under Capital Leases
    
 759 
    
 415 
Construction Expenditures Included in Current Liabilities at June 30,
    
 14,881 
    
 8,319 
Cash Dividends Declared but Not Paid
    
 15,000 
    
 - 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
131
 
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 146.

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




 
 
132
 

 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
 
 
133
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

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 scheduled to be in service in the fourth quarter of 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  See “Turk Plant” section of Note 2.

Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million based upon an 11.25% return on common equity to be effective January 2013.  The requested base rate increase includes a return on and of the Texas jurisdictional share of Turk Plant generation investment at December 2011 and total estimated transmission costs of the Turk Plant along with associated costs, including operations and maintenance costs.  It also proposed vegetation management expenditures and includes recovery of the Stall Unit.

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 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report.  Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 146.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 201 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,
 
2012 
  
2011 
  
2012 
  
2011 
     
(in millions of KWHs)
Retail:
                      
 
Residential
  
 1,570 
    
 1,645 
    
 2,952 
    
 3,249 
 
Commercial
  
 1,643 
    
 1,664 
    
 2,954 
    
 3,029 
 
Industrial
  
 1,513 
    
 1,425 
    
 2,831 
    
 2,676 
 
Miscellaneous
  
 21 
    
 22 
    
 41 
    
 41 
Total Retail (a)
  
 4,747 
    
 4,756 
    
 8,778 
    
 8,995 
                       
Wholesale
  
 1,607 
    
 1,787 
    
 3,879 
    
 3,665 
                       
Total KWHs
  
 6,354 
    
 6,543 
    
 12,657 
    
 12,660 
                           
(a)
Represents energy delivered to distribution customers.

 
134
 
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,
     
2012 
  
2011 
  
2012 
  
2011 
     
(in degree days)
 
Actual - Heating (a)
  
 4 
    
 17 
    
 427 
    
 866 
 
Normal - Heating (b)
  
 27 
    
 28 
    
 773 
    
 773 
                           
 
Actual - Cooling (c)
  
 910 
    
 934 
    
 1,024 
    
 985 
 
Normal - Cooling (b)
  
 710 
    
 700 
    
 740 
    
 731 
                           
 
(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.
 
 
 
 
135
 

Second Quarter of 2012 Compared to Second Quarter of 2011
 
Reconciliation of Second Quarter of 2011 to Second Quarter of 2012
Net Income
(in millions)
                 
Second Quarter of 2011
        
$
 51 
                 
Changes in Gross Margin:
            
Retail Margins (a)
          
 6 
Transmission Revenues
          
 1 
Total Change in Gross Margin
          
 7 
             
Changes in Expenses and Other:
            
Other Operation and Maintenance
          
 2 
Asset Impairment and Other Related Charges
          
 (13)
Depreciation and Amortization
          
 (2)
Taxes Other Than Income Taxes
          
 (1)
Allowance for Equity Funds Used During Construction
          
 3 
Interest Expense
          
 (1)
Total Change in Expenses and Other
          
 (12)
                 
Income Tax Expense
          
 9 
                 
Second Quarter of 2012
        
$
 55 
                 
(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 electricity were as follows:

 
·
Retail Margins increased $6 million primarily due to the following:
  
   
·
A $9 million increase in wholesale fuel recovery.
  
   
This increase was partially offset by:
   
·
A $2 million decrease in weather-related usage primarily due to a 3% decrease in cooling degree days.
   
·
A $2 million decrease in municipal and cooperative revenues due to formula rate adjustments, partially offset by higher rates.

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

 
·
Other Operation and Maintenance expenses decreased $2 million primarily due to the following:
   
·
A $4 million decrease in generation maintenance expenses primarily due to the timing of planned plant outages.
   
This decrease was partially offset by:
   
·
A $2 million increase due to expenses related to the 2012 sustainable cost reductions.
 
·
Asset Impairment and Other Related Charges include a second quarter 2012 write-off of $13 million related to the expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap.
 
·
Depreciation and Amortization expenses increased $2 million primarily due to a greater depreciable base.
 
·
Allowance for Equity Funds Used During Construction increased $3 million primarily due to construction at the Turk Plant.
 
·
Income Tax Expense decreased $9 million primarily due to the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis and a decrease in pretax book income.
 
 
 
136
 

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011
 
Reconciliation of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2012
Net Income
(in millions)
                   
Six Months Ended June 30, 2011
        
$
 81 
  
                   
Changes in Gross Margin:
              
Retail Margins (a)
          
 (5)
  
Off-system Sales
          
 1 
  
Transmission Revenues
          
 1 
  
Total Change in Gross Margin
          
 (3)
  
               
Changes in Expenses and Other:
              
Other Operation and Maintenance
          
 12 
  
Asset Impairment and Other Related Charges
          
 (13)
  
Depreciation and Amortization
          
 (3)
  
Interest Income
          
 1 
  
Allowance for Equity Funds Used During Construction
          
 6 
  
Total Change in Expenses and Other
          
 3 
  
                   
Income Tax Expense
          
 10 
  
                   
Six Months Ended June 30, 2012
        
$
 91 
  
                   
(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 electricity were as follows:

 
·
Retail Margins decreased $5 million primarily due to the following:
  
   
·
A $7 million decrease in weather-related usage primarily due to a decrease in heating and cooling degree days.
  
   
·
A $5 million decrease primarily due to fuel cost adjustments.
  
   
These decreases were partially offset by:
   
·
A $7 million increase in municipal and cooperative revenues due to formula rate adjustments and higher rates.

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

 
·
Other Operation and Maintenance expenses decreased $12 million primarily due to the following:
   
·
A $10 million decrease in generation maintenance expenses primarily due to the timing of planned plant outages.
   
·
A $3 million decrease in distribution maintenance expenses primarily due to decreased vegetation management and storm-related expenses.
   
These decreases were partially offset by:
   
·
A $2 million increase due to expenses related to the 2012 sustainable cost reductions.
 
·
Asset Impairment and Other Related Charges include a second quarter 2012 write-off of $13 million related to the expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap.
 
·
Depreciation and Amortization expenses increased $3 million primarily due to a greater depreciable base.
 
·
Allowance for Equity Funds Used During Construction increased $6 million primarily due to construction at the Turk Plant.
 
·
Income Tax Expense decreased $10 million primarily due to the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis.

 
137
 
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2011 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 Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of accounting pronouncements.
 
 
138
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
  
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
  
For the Three and Six Months Ended June 30, 2012 and 2011
  
(in thousands)
  
(Unaudited)
  
   
   
Three Months Ended
    
Six Months Ended
  
   
2012
    
2011
    
2012
    
2011
  
REVENUES
                        
Electric Generation, Transmission and Distribution
   $ 383,659     $ 388,197     $ 723,362     $ 735,264  
Sales to AEP Affiliates
     6,890       10,671       15,847       26,250  
Other Revenues
     397       666       723       975  
TOTAL REVENUES
     390,946       399,534       739,932       762,489  
                                 
EXPENSES
                                
Fuel and Other Consumables Used for Electric Generation
     138,008       139,713       266,242       273,725  
Purchased Electricity for Resale
     26,574       39,691       62,041       78,280  
Purchased Electricity from AEP Affiliates
     4,589       5,116       10,844       7,227  
Other Operation
     54,067       50,722       105,660       104,790  
Maintenance
     29,757       34,790       51,019       64,181  
Asset Impairment and Other Related Charges
     13,000       -       13,000       -  
Depreciation and Amortization
     34,655       32,718       68,676       66,008  
Taxes Other Than Income Taxes
     17,320       16,730       34,106       33,696  
TOTAL EXPENSES
     317,970       319,480       611,588       627,907  
                                 
OPERATING INCOME
     72,976       80,054       128,344       134,582  
                                 
Other Income (Expense):
                                
Interest Income
     11       167       1,132       111  
Allowance for Equity Funds Used During Construction
     14,412       11,573       28,185       22,169  
Interest Expense
     (21,710 )     (20,835 )     (43,712 )     (43,260 )
                                 
INCOME BEFORE INCOME TAX EXPENSE AND
                                
EQUITY EARNINGS
     65,689       70,959       113,949       113,602  
                                 
Income Tax Expense
     11,505       20,571       23,977       33,967  
Equity Earnings of Unconsolidated Subsidiary
     718       683       1,325       1,263  
                                 
NET INCOME
     54,902       51,071       91,297       80,898  
                                 
Net Income Attributable to Noncontrolling Interest
     1,061       1,036       2,144       2,118  
                                 
NET INCOME ATTRIBUTABLE TO SWEPCo
                                
SHAREHOLDERS
     53,841       50,035       89,153       78,780  
                                 
Preferred Stock Dividend Requirements
     -       57       -       114  
                                 
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON
                                
SHAREHOLDER
   $ 53,841     $ 49,978     $ 89,153     $ 78,666  
                                 
The common stock of SWEPCo is wholly-owned by AEP.
                                
                                 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
  
 
 
 
139
 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
  
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
  
For the Three and Six Months Ended June 30, 2012 and 2011
  
(in thousands)
  
(Unaudited)
  
                         
   
Three Months Ended
    
Six Months Ended
  
   
2012
    
2011
    
2012
    
2011
  
Net Income
   $ 54,902     $ 51,071     $ 91,297     $ 80,898  
                                 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                                
Cash Flow Hedges, Net of Tax of $213 and $65 for the Three Months Ended
                                
June 30, 2012 and 2011, Respectively, and $743 and $137 for the Six
                                
Months Ended June 30, 2012 and 2011, Respectively
     396       (121 )     (1,379 )     255  
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $90
                                
and $612 for the Three Months Ended June 30, 2012 and 2011,
                                
Respectively, and $179 and $681 for the Six Months Ended June 30,
                                
2012 and 2011, Respectively
     167       1,137       332       1,265  
                                 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
     563       1,016       (1,047 )     1,520  
                                 
TOTAL COMPREHENSIVE INCOME
     55,465       52,087       90,250       82,418  
                                 
Total Comprehensive Income Attributable to Noncontrolling Interest
     1,061       1,036       2,144       2,118  
                                 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo
                                
SHAREHOLDERS
   $ 54,404     $ 51,051     $ 88,106     $ 80,300  
                                 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
  
 
 
 
140
 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 30, 2012 and 2011
(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, 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 
                                     
Net Income
                
 78,780 
          
 2,118 
    
 80,898 
Other Comprehensive Income
                      
 1,520 
          
 1,520 
TOTAL EQUITY – JUNE 30, 2011
  
$
 135,660 
  
$
 674,979 
  
$
 947,506 
  
$
 (10,971)
  
$
 353 
  
$
 1,747,527 
                                     
TOTAL EQUITY – DECEMBER 31, 2011
  
$
 135,660 
  
$
 674,606 
  
$
 1,029,915 
  
$
 (26,815)
  
$
 391 
  
$
 1,813,757 
                                     
Common Stock Dividends – Nonaffiliated
                            
 (2,195)
    
 (2,195)
Subtotal – Equity
                                  
 1,811,562 
                                     
Net Income
                
 89,153 
          
 2,144 
    
 91,297 
Other Comprehensive Loss
                      
 (1,047)
          
 (1,047)
TOTAL EQUITY – JUNE 30, 2012
  
$
 135,660 
  
$
 674,606 
  
$
 1,119,068 
  
$
 (27,862)
  
$
 340 
  
$
 1,901,812 
                                     
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
 
 
141
 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)
 
   
2012 
  
2011 
CURRENT ASSETS
            
Cash and Cash Equivalents
            
   
(June 30, 2012 Amount Includes $13,517 Related to Sabine)
  
$
 14,617 
  
$
 801 
Advances to Affiliates
    
 97,022 
    
 - 
Accounts Receivable:
            
   
Customers
    
 39,210 
    
 35,054 
   
Affiliated Companies
    
 29,043 
    
 23,730 
   
Miscellaneous
    
 22,886 
    
 19,370 
   
Allowance for Uncollectible Accounts
    
 (960)
    
 (989)
     
Total Accounts Receivable
    
 90,179 
    
 77,165 
Fuel
            
   
(June 30, 2012 and December 31, 2011 Amounts Include $23,616 and
            
   
$32,651, Respectively, Related to Sabine)
    
 104,499 
    
 102,015 
Materials and Supplies
    
 69,742 
    
 55,325 
Risk Management Assets
    
 1,297 
    
 445 
Deferred Income Tax Benefits
    
 7,286 
    
 8,195 
Accrued Tax Benefits
    
 52,285 
    
 1,541 
Regulatory Asset for Under-Recovered Fuel Costs
    
 12,835 
    
 10,843 
Prepayments and Other Current Assets
    
 25,930 
    
 16,827 
TOTAL CURRENT ASSETS
    
 475,692 
    
 273,157 
             
PROPERTY, PLANT AND EQUIPMENT
            
Electric:
            
   
Generation
    
 2,332,494 
    
 2,326,102 
   
Transmission
    
 1,053,582 
    
 988,534 
   
Distribution
    
 1,721,839 
    
 1,675,764 
Other Property, Plant and Equipment
            
   
(June 30, 2012 and December 31, 2011 Amounts Include $245,607 and
            
   
$232,948, Respectively, Related to Sabine)
    
 660,819 
    
 637,019 
Construction Work in Progress
    
 1,520,783 
    
 1,443,569 
Total Property, Plant and Equipment
    
 7,289,517 
    
 7,070,988 
Accumulated Depreciation and Amortization
            
   
(June 30, 2012 and December 31, 2011 Amounts Include $107,859 and
            
   
$103,586, Respectively, Related to Sabine)
    
 2,249,214 
    
 2,211,912 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    
 5,040,303 
    
 4,859,076 
             
OTHER NONCURRENT ASSETS
            
Regulatory Assets
    
 423,048 
    
 394,276 
Long-term Risk Management Assets
    
 368 
    
 282 
Deferred Charges and Other Noncurrent Assets
    
 98,986 
    
 74,992 
TOTAL OTHER NONCURRENT ASSETS
    
 522,402 
    
 469,550 
             
TOTAL ASSETS
  
$
 6,038,397 
  
$
 5,601,783 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
 
 
142
 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2012 and December 31, 2011
(Unaudited)
 
   
2012 
  
2011 
     
(in thousands)
CURRENT LIABILITIES
            
Advances from Affiliates
  
$
 - 
  
$
 132,473 
Accounts Payable:
            
   
General
    
 155,153 
    
 181,268 
   
Affiliated Companies
    
 58,582 
    
 59,201 
Short-term Debt – Nonaffiliated
    
 - 
    
 17,016 
Long-term Debt Due Within One Year – Nonaffiliated
    
 3,250 
    
 20,000 
Risk Management Liabilities
    
 8,009 
    
 24,359 
Customer Deposits
    
 53,552 
    
 52,095 
Accrued Taxes
    
 54,527 
    
 44,404 
Accrued Interest
    
 43,685 
    
 39,629 
Obligations Under Capital Leases
    
 16,695 
    
 15,058 
Regulatory Liability for Over-Recovered Fuel Costs
    
 2,626 
    
 5,032 
Other Current Liabilities
    
 67,227 
    
 64,413 
TOTAL CURRENT LIABILITIES
    
 463,306 
    
 654,948 
             
NONCURRENT LIABILITIES
            
Long-term Debt – Nonaffiliated
    
 2,044,426 
    
 1,708,637 
Long-term Risk Management Liabilities
    
 335 
    
 221 
Deferred Income Taxes
    
 828,904 
    
 665,668 
Regulatory Liabilities and Deferred Investment Tax Credits
    
 459,529 
    
 428,571 
Asset Retirement Obligations
    
 80,851 
    
 65,673 
Employee Benefits and Pension Obligations
    
 91,985 
    
 87,159 
Obligations Under Capital Leases
    
 115,535 
    
 112,802 
Deferred Credits and Other Noncurrent Liabilities
    
 51,714 
    
 64,347 
TOTAL NONCURRENT LIABILITIES
    
 3,673,279 
    
 3,133,078 
             
TOTAL LIABILITIES
    
 4,136,585 
    
 3,788,026 
             
Rate Matters (Note 2)
            
Commitments and Contingencies (Note 3)
            
             
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
    
 674,606 
    
 674,606 
Retained Earnings
    
 1,119,068 
    
 1,029,915 
Accumulated Other Comprehensive Income (Loss)
    
 (27,862)
    
 (26,815)
TOTAL COMMON SHAREHOLDER’S EQUITY
    
 1,901,472 
    
 1,813,366 
             
Noncontrolling Interest
    
 340 
    
 391 
             
TOTAL EQUITY
    
 1,901,812 
    
 1,813,757 
             
TOTAL LIABILITIES AND EQUITY
  
$
 6,038,397 
  
$
 5,601,783 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
 
143
 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)
 
   
2012 
  
2011 
OPERATING ACTIVITIES
            
Net Income
  
$
 91,297 
  
$
 80,898 
Adjustments to Reconcile Net Income to Net Cash Flows from
            
 
 Operating Activities:
            
   
Depreciation and Amortization
    
 68,676 
    
 66,008 
   
Deferred Income Taxes
    
 138,594 
    
 23,562 
   
Asset Impairment and Other Related Charges
    
 13,000 
    
 - 
   
Allowance for Equity Funds Used During Construction
    
 (28,185)
    
 (22,169)
   
Mark-to-Market of Risk Management Contracts
    
 1,927 
    
 (1,863)
   
Property Taxes
    
 (19,790)
    
 (20,356)
   
Fuel Over/Under-Recovery, Net
    
 (4,398)
    
 (25,144)
   
Change in Other Noncurrent Assets
    
 1,678 
    
 17,791 
   
Change in Other Noncurrent Liabilities
    
 17,707 
    
 27,255 
   
Changes in Certain Components of Working Capital:
            
     
Accounts Receivable, Net
    
 (12,989)
    
 9,062 
     
Fuel, Materials and Supplies
    
 (16,901)
    
 (8,929)
     
Accounts Payable
    
 2,938 
    
 37,823 
     
Accrued Taxes, Net
    
 (40,616)
    
 24,753 
     
Other Current Assets
    
 (7,685)
    
 (1,485)
     
Other Current Liabilities
    
 (6,367)
    
 2,657 
Net Cash Flows from Operating Activities
    
 198,886 
    
 209,863 
             
INVESTING ACTIVITIES
            
Construction Expenditures
    
 (246,957)
    
 (237,834)
Change in Advances to Affiliates, Net
    
 (97,022)
    
 51,538 
Other Investing Activities
    
 (1,927)
    
 (7,953)
Net Cash Flows Used for Investing Activities
    
 (345,906)
    
 (194,249)
             
FINANCING ACTIVITIES
            
Issuance of Long-term Debt – Nonaffiliated
    
 336,576 
    
 - 
Credit Facility Borrowings
    
 21,462 
    
 27,413 
Change in Advances from Affiliates, Net
    
 (132,473)
    
 - 
Retirement of Long-term Debt – Nonaffiliated
    
 (20,000)
    
 - 
Retirement of Cumulative Preferred Stock
    
 - 
    
 (1)
Credit Facility Repayments
    
 (38,478)
    
 (33,630)
Principal Payments for Capital Lease Obligations
    
 (7,899)
    
 (6,655)
Dividends Paid on Common Stock – Nonaffiliated
    
 (2,195)
    
 (2,126)
Dividends Paid on Cumulative Preferred Stock
    
 - 
    
 (114)
Other Financing Activities
    
 3,843 
    
 74 
Net Cash Flows from (Used for) Financing Activities
    
 160,836 
    
 (15,039)
             
Net Increase in Cash and Cash Equivalents
    
 13,816 
    
 575 
Cash and Cash Equivalents at Beginning of Period
    
 801 
    
 1,514 
Cash and Cash Equivalents at End of Period
  
$
 14,617 
  
$
 2,089 
             
SUPPLEMENTARY INFORMATION
            
Cash Paid for Interest, Net of Capitalized Amounts
  
$
 32,595 
  
$
 37,681 
Net Cash Paid (Received) for Income Taxes
    
 (47,741)
    
 8,026 
Noncash Acquisitions Under Capital Leases
    
 12,350 
    
 4,378 
Construction Expenditures Included in Current Liabilities at June 30,
    
 79,960 
    
 96,959 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.
 
 
144
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to SWEPCo’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 SWEPCo.  The footnotes begin on page 146.

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

 
145
 
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, I&M, OPCo, PSO, SWEPCo
2.
Rate Matters
APCo, I&M, OPCo, PSO, SWEPCo
3.
Commitments, Guarantees and Contingencies
APCo, I&M, OPCo, PSO, SWEPCo
4.
Benefit Plans
APCo, I&M, OPCo, PSO, SWEPCo
5.
Business Segments
APCo, I&M, OPCo, PSO, SWEPCo
6.
Derivatives and Hedging
APCo, I&M, OPCo, PSO, SWEPCo
7.
Fair Value Measurements
APCo, I&M, OPCo, PSO, SWEPCo
8.
Income Taxes
APCo, I&M, OPCo, PSO, SWEPCo
9.
Financing Activities
APCo, I&M, OPCo, PSO, SWEPCo
10.
Sustainable Cost Reductions
APCo, I&M, OPCo, PSO, SWEPCo

 
146
 
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, 2012 is not necessarily indicative of results that may be expected for the year ending December 31, 2012.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2011 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2011 as filed with the SEC on February 28, 2012.

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, variable interests held by related parties 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, I&M, OPCo, PSO and SWEPCo each hold a significant variable interest in AEPSC.  I&M and OPCo 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 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, 2012 and 2011 were $36 million and $30 million, respectively, and for the six months ended June 30, 2012 and 2011 were $91 million and $64 million, respectively.  See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets.
 
147
 
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, 2012 and December 31, 2011
(in thousands)
   
Sabine
ASSETS
  
2012 
  
2011 
Current Assets
  
$
 66,966 
  
$
 48,044 
Net Property, Plant and Equipment
    
 169,929 
    
 153,715 
Other Noncurrent Assets
    
 57,005 
    
 42,574 
Total Assets
  
$
 293,900 
  
$
 244,333 
             
LIABILITIES AND EQUITY
            
Current Liabilities
  
$
 42,028 
  
$
 67,779 
Noncurrent Liabilities
    
 251,532 
    
 176,163 
Equity
    
 340 
    
 391 
Total Liabilities and Equity
  
$
 293,900 
  
$
 244,333 

I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC and DCC Fuel V 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.  Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the leases for the three months ended June 30, 2012 and 2011 were $42 million and $38 million, respectively, and for the six months ended June 30, 2012 and 2011 were $59 million and $43 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 respective lease terms, which do not exceed 54 months.  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 table below for the classification of DCC Fuel’s assets and liabilities on I&M’s condensed 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, 2012 and December 31, 2011
(in thousands)
   
DCC Fuel
ASSETS
  
2012 
  
2011 
Current Assets
  
$
 146,857 
  
$
 118,144 
Net Property, Plant and Equipment
    
 240,961 
    
 188,375 
Other Noncurrent Assets
    
 142,837 
    
 117,772 
Total Assets
  
$
 530,655 
  
$
 424,291 
             
LIABILITIES AND EQUITY
            
Current Liabilities
  
$
 126,595 
  
$
 102,946 
Noncurrent Liabilities
    
 404,060 
    
 321,345 
Equity
    
 - 
    
 - 
Total Liabilities and Equity
  
$
 530,655 
  
$
 424,291 

 
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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 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, 2012 and 2011 were $20 million and $15 million, respectively, and for the six months ended June 30, 2012 and 2011 were $34 million and $29 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 balance sheets.

SWEPCo’s investment in DHLC was:

   
June 30, 2012
  
December 31, 2011
   
As Reported on
  
Maximum
  
As Reported on
  
Maximum
   
the Balance Sheet
Exposure
the Balance Sheet
  
Exposure
   
(in thousands)
Capital Contribution from SWEPCo
  
$
 7,643 
  
$
 7,643 
  
$
 7,643 
  
$
 7,643 
Retained Earnings
    
 1,163 
    
 1,163 
    
 1,120 
    
 1,120 
SWEPCo's Guarantee of Debt
    
 - 
    
 56,706 
    
 - 
    
 52,310 
                         
Total Investment in DHLC
  
$
 8,806 
  
$
 65,512 
  
$
 8,763 
  
$
 61,073 

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 their 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
  
2012 
  
2011 
  
2012 
  
2011 
   
(in thousands)
APCo
  
$
 43,894 
  
$
 47,352 
  
$
 82,440 
  
$
 92,293 
I&M
    
 31,377 
    
 31,006 
    
 57,484 
    
 62,834 
OPCo
    
 67,490 
    
 72,992 
    
 120,935 
    
 136,869 
PSO
    
 21,301 
    
 21,130 
    
 38,897 
    
 40,548 
SWEPCo
    
 33,246 
    
 31,560 
    
 59,966 
    
 61,393 

The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows:

   
June 30, 2012
  
December 31, 2011
   
As Reported on the
  
Maximum
  
As Reported on the
  
Maximum
Company
  
Balance Sheet
  
Exposure
  
Balance Sheet
  
Exposure
   
(in thousands)
APCo
  
$
 16,077 
  
$
 16,077 
  
$
 20,812 
  
$
 20,812 
I&M
    
 11,526 
    
 11,526 
    
 13,741 
    
 13,741 
OPCo
    
 19,233 
    
 19,233 
    
 29,823 
    
 29,823 
PSO
    
 8,067 
    
 8,067 
    
 9,280 
    
 9,280 
SWEPCo
    
 12,302 
    
 12,302 
    
 14,699 
    
 14,699 

 
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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 OPCo.  AEP guarantees all the debt obligations of AEGCo.  I&M and OPCo are considered to have a significant interest in AEGCo due to these transactions.  I&M and OPCo 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, OPCo and KPCo, this financing would be provided by AEP.  For additional information regarding AEGCo’s lease, see the “Rockport Lease” section of Note 12 in the 2011 Annual Report.

Total billings from AEGCo were as follows:

   
Three Months Ended June 30,
  
Six Months Ended June 30,
Company
  
2012 
  
2011 
  
2012 
  
2011 
   
(in thousands)
I&M
  
$
 53,917 
  
$
 49,852 
  
$
 112,739 
  
$
 102,673 
OPCo
    
 44,823 
    
 40,983 
    
 103,239 
    
 92,017 

The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows:
 
   
June 30, 2012
  
December 31, 2011
   
As Reported on
  
Maximum
  
As Reported on
  
Maximum
Company
  
the Balance Sheet
  
Exposure
  
the Balance Sheet
  
Exposure
   
(in thousands)
I&M
  
$
 20,912 
  
$
 20,912 
  
$
 25,731 
  
$
 25,731 
OPCo
    
 16,822 
    
 16,822 
    
 22,139 
    
 22,139 

CSPCo-OPCo Merger

On December 31, 2011, CSPCo merged into OPCo with OPCo being the surviving entity.  All prior reported amounts have been recast as if the merger occurred on the first day of the earliest reporting period.   All contracts and operations of CSPCo and its subsidiary are now part of OPCo.
 
150
 
2.  RATE MATTERS

As discussed in the 2011 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 2011 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 2012 and updates the 2011 Annual Report.

Regulatory Assets Not Yet Being Recovered

       
APCo
       
June 30,
  
December 31,
       
2012 
  
2011 
Noncurrent Regulatory Assets (excluding fuel)
  
(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
  
$
 22,336 
  
$
 17,950 
 
Mountaineer Carbon Capture and Storage
            
   
Product Validation Facility
    
 14,155 
    
 14,155 
 
Special Rate Mechanism for Century Aluminum
    
 12,939 
    
 12,811 
 
Dresden Operating Costs
    
 7,265 
    
 - 
 
Virginia Deferred Wind Power Costs
    
 4,277 
    
 38,192 
 
Transmission Agreement Phase-In
    
 2,510 
    
 1,925 
 
Mountaineer Carbon Capture and Storage
            
   
Commercial Scale Facility
    
 1,289 
    
 1,335 
 
Other Regulatory Assets Not Yet Being Recovered
    
 3,049 
    
 1,010 
Total Regulatory Assets Not Yet Being Recovered
  
$
 67,820 
  
$
 87,378 

       
I&M
       
June 30,
  
December 31,
       
2012 
  
2011 
Noncurrent Regulatory Assets (excluding fuel)
  
(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
            
 
Litigation Settlement
  
$
 10,954 
  
$
 10,803 
 
Mountaineer Carbon Capture and Storage
            
   
Commercial Scale Facility
    
 1,382 
    
 1,680 
 
Other Regulatory Asset Not Being Recovered
    
 658 
    
 - 
Total Regulatory Assets Not Yet Being Recovered
  
$
 12,994 
  
$
 12,483 

       
OPCo
       
June 30,
  
December 31,
       
2012 
  
2011 
Noncurrent Regulatory Assets (excluding fuel)
  
(in thousands)
Regulatory assets not yet being recovered pending future proceedings to determine
            
 
the recovery method and timing:
            
Regulatory Assets Currently Earning a Return
            
 
Economic Development Rider
  
$
 12,892 
  
$
 12,572 
Regulatory Assets Currently Not Earning a Return
            
 
Storm Related Costs
    
 - 
    
 8,375 
Total Regulatory Assets Not Yet Being Recovered
  
$
 12,892 
  
$
 20,947 

 
151
 
       
SWEPCo
       
June 30,
  
December 31,
       
2012 
  
2011 
Noncurrent Regulatory Assets (excluding fuel)
  
(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
            
 
Rate Case Expenses
  
$
 2,760 
  
$
 - 
 
Mountaineer Carbon Capture and Storage
            
   
Commercial Scale Facility
    
 2,298 
    
 2,380 
 
Other Regulatory Assets Not Yet Being Recovered
    
 2,006 
    
 1,699 
Total Regulatory Assets Not Yet Being Recovered
  
$
 7,064 
  
$
 4,079 

OPCo Rate Matters

Ohio Electric Security Plan Filing

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011.  OPCo collected the 2009 annualized revenue increase over the last nine months of 2009.  The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018.  See the “January 2012 – May 2016 ESP as Rejected by the PUCO” section below.  The PUCO’s March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO.

In October 2011, the PUCO issued an order in the remand proceeding.  As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011.  In February 2012, the Ohio Consumers’ Counsel and the Industrial Energy Users-Ohio (IEU) filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which if ordered could total up to $698 million, excluding carrying costs.

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off of certain pretax earnings in 2010 and a subsequent refund to customers during 2011.  In May 2011, the IEU and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO’s SEET decision.  The OEG’s appeal seeks the inclusion of off-system sales (OSS) in the calculation of SEET which, if ordered, could require an additional refund of $22 million based on the PUCO approved SEET calculation.  The IEU’s appeal also sought the inclusion of OSS as well as other items in the determination of SEET, but did not quantify the amount.  Oral arguments were held in March 2012 and management is unable to predict the outcome of the appeals.  If the Supreme Court of Ohio ultimately determines that additional amounts should be refunded, it could reduce future net income and cash flows and impact financial condition.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings, which included OSS in the SEET calculation.  In December 2011, the PUCO staff filed testimony that recommended a $23 million refund of 2010 earnings.  In the fourth quarter of 2011, OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO ordered SEET refund.  OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis.  The PUCO approved OPCo’s request to file the 2011 SEET on July 31, 2012 or one month after the PUCO issues an order on the 2010 SEET, whichever is later.  Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo.

Management is unable to predict the outcome of the unresolved 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.
 
152
 
January 2012 – May 2016 ESP as Rejected by the PUCO

In December 2011, the PUCO approved a modified stipulation which established a new ESP that included a standard service offer (SSO) pricing for generation.  Various parties filed for rehearing with the PUCO requesting that the PUCO reconsider adoption of the modified stipulation.  In February 2012, the PUCO issued an entry on rehearing which rejected the modified stipulation and ordered a return to the 2011 ESP rates until a new rate plan is approved.

As directed by the February 2012 order, OPCo filed revised tariffs with the PUCO to implement the provisions of the 2011 ESP.  Included in the revised tariffs was the Phase-In Recovery Rider (PIRR) to recover deferred fuel costs as authorized under the 2009 – 2011 ESP order.  See the “2009 – 2011 ESP” section above.  In March 2012, the PUCO issued an order that directed OPCo to file new revised tariffs removing the PIRR and stated that its recovery would be addressed in a future proceeding.  OPCo implemented the new revised tariffs in March 2012.  In March 2012, OPCo resumed recording a weighted average cost of capital return on the PIRR deferral in accordance with the 2009 - 2011 ESP order.  Also in March 2012, OPCo filed a request for rehearing of the March 2012 order relating to the PIRR, which the PUCO denied but provided that all of the substantive concerns and issues raised would be deferred into a separate PIRR docket.  See the “Proposed June 2012 – May 2015 ESP” section below.

As a result of the PUCO’s rejection of the modified stipulation, in the first quarter of 2012, OPCo reversed a $35 million obligation to contribute to Partnership with Ohio and Ohio Growth Fund and an $8 million regulatory asset for 2011 storm damage, both originally recorded in the fourth quarter of 2011.

In March 2012, in response to OPCo’s motion for relief, the PUCO ordered that CRES providers not qualifying for the tier one capacity billing rate of $146/MW day, which is substantially below OPCo’s current capacity cost of approximately $355/MW day, will pay a tier two capacity billing rate of $255/MW day through May 2012.  The PUCO subsequently extended that order until August 8, 2012 or until an order is issued in OPCo’s pending June 2012 – May 2015 ESP proceeding, whichever is sooner.  See the “Proposed June 2012 – May 2015 ESP” section below.

Proposed June 2012 – May 2015 ESP

In March 2012, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing.  The SSO rates would be effective through May 2015.  The ESP will transition OPCo to an auction-based SSO for capacity and energy by June 2015.  OPCo also filed an application with the PUCO for approval of the corporate separation of its generation assets including the transfer of generation assets to a nonregulated AEP subsidiary at net book value.  Contingent upon OPCo receiving final orders from the PUCO adopting the ESP as proposed and the corporate separation plan as filed, OPCo will conduct an energy-only auction for 5% of the SSO load with delivery beginning six months after the final orders and extending through December 2014.  In addition, a competitive bidding process would determine the price of energy for OPCo’s SSO load from January 2015 through May 2015.  The ESP proposed a two-tiered capacity pricing structure for CRES providers.  The first tier is priced at the Reliability Pricing Model (RPM) rate in effect in March 2012 of $146/MW day to serve approximately 21%, 31% and 41% of each customer class through December 2012, December 2013 and for the period January 2014 through May 2015, respectively.  All other capacity provided to CRES providers would be offered at $255/MW day.  In 2012, an additional amount of capacity may be made available at the $146/MW day rate to accommodate any community aggregation load above 21%, if applicable.

The resolution of the capacity rate is also the subject of separate proceedings before the FERC and the PUCO.  In those proceedings, OPCo is seeking a wholesale cost-based capacity rate, currently at approximately $355/MW day.  In July 2012, the PUCO issued an order in the capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer its incurred capacity costs not recovered from CRES providers to the extent that the total incurred capacity costs do not exceed $188.88/MW day.  The RPM price is approximately $20/MW day through May 2013.  The order stated that the PUCO would establish an appropriate recovery mechanism in the pending June 2012 – May 2015 ESP proceeding.  The PUCO postponed implementation of the order until August 8, 2012 or until an order is issued in OPCo’s pending June 2012 – May 2015 ESP proceeding, whichever is sooner.  In July 2012, OPCo requested rehearing of the PUCO order.  If OPCo is ultimately not permitted to fully recover its capacity cost deferral, it would reduce future net income and cash flows and impact financial condition.
 
153
 
The ESP also proposed to collect the PIRR from June 2013 through December 2018.  As of June 30, 2012, the net PIRR deferral was $538 million, excluding unrecognized equity carrying costs.  If OPCo is ultimately not permitted to fully recover its PIRR deferral, it would reduce future net income and cash flows and impact financial condition.

Further, the ESP proposed establishment of a non-bypassable Distribution Investment Rider through May 2015 to recover, with certain caps, post-August 2010 distribution investment.  The filing also seeks establishment of a new non-bypassable Retail Stability Rider (RSR) to recover lost generation revenues to provide financial certainty and stability during the ESP transition period.  The proposed RSR would be effective through May 2015.  Finally, the ESP proposed a storm damage recovery mechanism for the deferral of operation and maintenance costs above $5 million, effective January 2012.

Intervenors and the PUCO staff filed testimony in May 2012 in opposition to many aspects of OPCo’s ESP, including the proposed RSR and the two-tiered capacity pricing structure for CRES providers.  Intervenors recommended a flash cut to the current RPM rate for capacity.  In addition, the PUCO staff’s testimony included a proposal to increase the vegetation management base used for calculating over/under recovery on incremental vegetation spend from $21 million to $39 million, which could increase future Other Operation and Maintenance expense by $18 million on an annual basis.

Hearings on the June 2012 – May 2015 ESP were held at the PUCO during the second quarter of 2012 and oral arguments were held in July 2012.  A decision from the PUCO is expected in August 2012.
 
2011 Ohio Distribution Base Rate Case

In February 2011, OPCo filed with the PUCO for an annual increase in distribution rates of $94 million based upon an 11.15% return on common equity to be effective January 2012.  In December 2011, a stipulation was approved by the PUCO which provided for no change in distribution rates and a new rider for a $15 million annual credit to residential ratepayers due principally to the inclusion of the rate base distribution investment in the Distribution Investment Rider (DIR) as approved by the modified stipulation in the ESP proceeding.

Because the February 2012 PUCO order rejected the ESP modified stipulation, collection of the DIR terminated.  In March 2012, OPCo filed an application with the PUCO to approve an ESP for the period June 2012 through May 2015, which includes a request for a new DIR.  See the “Proposed June 2012 – May 2015 ESP” section above.  A decision in the June 2012 – May 2015 ESP proceeding is expected in August 2012.  In March 2012, the PUCO issued an order clarifying that OPCo has the right to file a new distribution base rate case.  If OPCo is not ultimately permitted to fully recover its costs, it would reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

The PUCO selected an outside consultant to conduct an audit of OPCo’s FAC for 2009.  The outside consultant provided its audit report to the PUCO.  In January 2012, the PUCO ordered that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance.  In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges.  OPCo recorded a $30 million net favorable adjustment on the statement of income in the second quarter of 2012.  The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.  Management is unable to predict the outcome of any future consultant recommendation.  If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultants’ review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

In June 2012, OPCo filed a notice of appeal with the Supreme Court of Ohio challenging the PUCO’s decision to have proceeds from the 2008 coal contract settlement applied to OPCo’s under recovered fuel balance.  The PUCO filed a motion to dismiss OPCo’s notice of appeal at the Supreme Court of Ohio.  A decision is pending from the Supreme Court of Ohio.
 
154
 
2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its results of the 2010 and 2011 FAC audits.  The audit reports included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes.  As of June 30, 2012, the amount of OPCo’s carrying costs that could potentially be reduced due to the accumulated income tax issue is estimated to be approximately $34 million, including $18 million of unrecognized equity carrying costs.  Decisions from the PUCO are pending.  Management is unable to predict the outcome of these proceedings.  If the PUCO orders result in a reduction to the FAC deferral, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

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 filing and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio.  The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record a regulatory asset for the difference between the approved market price and the rate paid by Ormet.  Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs.  In November 2009, OPCo requested that the PUCO approve recovery of the deferral under the interim agreement plus a weighted average cost of capital carrying charge.  The deferral amount is included in OPCo’s FAC phase-in deferral balance.  In the ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related regulatory asset and requested that the PUCO prevent 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 OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.  This issue remains pending before the PUCO.  If OPCo is not ultimately permitted to fully recover its requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  Through June 30, 2012, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order.  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 these proceedings concerning the Ohio IGCC plant or what effect, if any, these proceedings would have on future net income and cash flows.  However, if OPCo is required to refund pre-construction costs collected, it could 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 scheduled to be in service in the fourth quarter of 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.8 billion, excluding AFUDC, plus an additional $120 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $120 million for transmission, excluding AFUDC.  As of June 30, 2012, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital costs cap, SWEPCo has capitalized approximately $1.6 billion of expenditures, including AFUDC and capitalized interest of $269 million for generation and related transmission costs of $121 million.  As of June 30, 2012, the joint owners and SWEPCo have contractual construction obligations of approximately $65 million (including related transmission costs of $3 million).  SWEPCo’s share of the contractual construction obligations is $48 million.
 
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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.  SWEPCo announced that it would continue construction of the Turk Plant and would not currently seek authority to serve Arkansas retail customers.  In June 2010, in response to the Arkansas Supreme Court's decision, the APSC issued an order which reversed and set aside the previously granted CECPN.  SWEPCo currently has no contracts for the 88 MW of Turk Plant output but is evaluating its options.

The PUCT approved 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 (TIEC) filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers.  The Texas District Court and the Texas Court of Appeals affirmed the PUCT’s order in all respects.  In April 2012, SWEPCo and TIEC filed petitions for review at the Supreme Court of Texas.

If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could materially reduce future net income and cash flows and materially impact financial condition.

2012 Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million based upon an 11.25% return on common equity to be effective January 2013.  The requested base rate increase includes a return on and of the Texas jurisdictional share of Turk Plant generation investment at December 2011 and total estimated transmission costs of the Turk Plant along with associated costs, including operations and maintenance costs.  It also proposed vegetation management expenditures and includes recovery of the Stall Unit.

Louisiana 2010 Formula Rate Filing

In April 2010, SWEPCo filed its third formula rate plan (FRP) which decreased annual Louisiana retail rates by $3 million effective August 2010, subject to refund.  In October 2010 and September 2011, consultants for the LPSC filed testimony objecting to certain components of SWEPCo’s FRP calculations.  Hearings were scheduled for May 2012 but were postponed pending settlement negotiations.  In the second quarter of 2012, SWEPCo recorded a reserve related to these settlement negotiations.  Management believes that the reserve is adequate to pay any refunds.  However, if the LPSC orders a refund greater than the booked reserve, it would reduce future net income and cash flows.
 
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APCo Rate Matters

Virginia Fuel Filing

In April 2012, APCo filed an application with the Virginia SCC for an annual increase in fuel revenues of $117 million to be effective June 2012.  The filing included forecasted costs for the 15-month period ended August 2013 and requested recovery of APCo's anticipated unrecovered fuel balance as of May 2012 over a two-year period commencing in June 2012.  The non-incremental portion of APCo's forecasted and deferred wind purchased power costs were reflected in APCo's filing.  In June 2012, the Virginia SCC approved the application as filed.

Environmental Rate Adjustment Clause (RAC)

In November 2011, the Virginia SCC issued an order which approved APCo’s environmental RAC recovery of $30 million to be collected over one year beginning in February 2012 but denied recovery of certain environmental costs.  As a result, in the fourth quarter of 2011, APCo recorded a pretax write-off of $31 million on the statement of income related to environmental compliance costs incurred from January 2009 through December 2010.  In December 2011, APCo filed a notice of appeal with the Supreme Court of Virginia regarding this decision.  If the Supreme Court of Virginia were to issue a favorable decision, it could increase future net income and cash flows.

APCo’s Filings for an IGCC Plant

Through June 30, 2012, 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.  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 March 2012, West Virginia passed securitization legislation, which allows the WVPSC to establish a regulatory framework to securitize certain deferred ENEC balances and other ENEC related assets.  Also in March 2012, APCo and WPCo filed their ENEC application with the WVPSC for the fourth year of a four year phase-in plan which requested no change in ENEC rates if the WVPSC issues a financing order allowing securitization of the under-recovered ENEC deferral and other ENEC related assets.  The proposed rates consist of a Dresden Plant surcharge of $32 million and an increase in the construction surcharge of $2 million, offset by a reduction of $34 million in current ENEC rates.  APCo and WPCo anticipate filing, in the third quarter of 2012, a request for a financing order with the WVPSC pursuant to the securitization legislation.  Upon completion of the securitization, APCo and WPCo would offset the then current ENEC rates by an amount recovered through the securitization.  If the financing order is not issued, APCo and WPCo requested recovery of these costs in current rates.  As of June 30, 2012, APCo’s ENEC under-recovery balance of $326 million was recorded in Regulatory Assets on the balance sheet, excluding $6 million of unrecognized equity carrying costs.

In June 2012, a settlement agreement was filed with the WVPSC which recommended no change in total ENEC rates but reflected a $24 million increase in the construction surcharge and a $24 million decrease in ENEC rates.  The settlement agreement did not address an intervenor recommendation that the fuel cost recovery for the Mountaineer Plant be limited to the prudently incurred cost of high sulfur coal which, if approved by the WVPSC, could result in a disallowance of approximately $14 million.  Approval of the settlement agreement is pending before the WVPSC.  If the WVPSC were to disallow a portion of APCo’s and WPCo’s deferred ENEC costs, it could reduce APCo’s 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, the Virginia SCC and the FERC are required.  In December 2011 and February 2012, APCo and WPCo filed merger applications with the WVPSC and the FERC, respectively.  In February 2012, APCo and WPCo withdrew their merger application with the FERC.  Management intends to refile a merger application with the FERC and also file a merger application with the Virginia SCC in the future.
 
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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 prudence 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.  In June 2012, an Administrative Law Judge issued a report that affirmed the margin sharing amount of 25% and found that the OCC does not have the jurisdiction to grant the relief sought by the OIEC regarding the comprehensive review of all affiliate fuel transactions and the ERCOT trading contracts.  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

2011 Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on common equity of 11.15%.  The $149 million net annual increase reflects an increase in base rates of $178 million offset by proposed corresponding reductions of $13 million to the off-system sales sharing rider, $9 million to the PJM cost rider and $7 million to the clean coal technology rider rates.  The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.

In May 2012, the Indiana Office of Utility Consumer Counselor filed testimony that recommended an increase in base rates of $28 million, excluding reductions to certain riders, based upon a return on common equity of 9.2%.  I&M filed rebuttal testimony in May 2012 which supported an increase of $170 million in base rates, excluding reductions to certain riders.  Final hearings were held in June 2012.  A decision from the IURC is expected in the fourth quarter of 2012.

Life Cycle Management Project

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects for Cook Plant Units 1 and 2.  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.

In Indiana, I&M requested recovery of certain project costs, including interest, through a rider effective January 2013.  In Michigan, I&M requested that the MPSC approve a Certificate of Public Convenience and Necessity and authorize I&M to defer, on an interim basis, incremental depreciation and property tax costs, including interest, along with study, analysis and development costs until the applicable costs are included in I&M’s base rates.  As of June 30, 2012, I&M has incurred $92 million related to the LCM Project.  If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.
 
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FERC Rate Matters

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

In 2004, AEP eliminated transaction-based through-and-out transmission service charges and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA through March 2006.  Intervenors objected and 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.  APCo’s, I&M’s and OPCo’s portions of recognized gross SECA revenues are as follows:

Company
  
(in millions)
APCo
  
$
 70.2 
I&M
    
 41.3 
OPCo
    
 92.1 

In 2006, a FERC Administrative Law Judge 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.

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 supported AEP’s position and required a compliance filing.

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, I&M’s and OPCo’s portions of the provision are as follows:

Company
  
(in millions)
APCo
  
$
 14.1 
I&M
    
 8.3 
OPCo
    
 18.5 

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, 2012 was $32 million.  APCo’s, I&M’s and OPCo’s reserve balances as of June 30, 2012 were:

Company
  
June 30, 2012
   
(in millions)
APCo
  
$
 10.0 
I&M
    
 5.9 
OPCo
    
 13.2 

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, 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 
I&M
    
 3.7 
    
 1.9 
OPCo
    
 8.3 
    
 4.2 

 
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Based on the 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 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, I&M and OPCo

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC.  It is unknown at this time whether the Interconnection Agreement 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.  Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future.  If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement 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.

3.  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 effect on the financial statements.  The Commitments, Guarantees and Contingencies note within the 2011 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 credit facilities totaling $3.25 billion, under which up to $1.35 billion may be issued as letters of credit.  As of June 30, 2012, the maximum future payments for letters of credit issued under the credit facilities were as follows:

Company
  
Amount
  
Maturity
   
(in thousands)
    
I&M
  
$
 150 
  
March 2013
SWEPCo
    
 4,448 
  
March 2013

 
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The Registrant Subsidiaries have $357 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $361 million as follows:

         
Bilateral
  
Maturity of
   
Pollution
  
Letters
  
Bilateral Letters
Company
  
Control Bonds
  
of Credit
  
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 
    
 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 $115 million.  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.  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, 2012, SWEPCo has collected approximately $56 million through a rider for final mine closure and reclamation costs, of which $11 million is recorded in Other Current Liabilities, $3 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $42 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed 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, 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, 2012, there were no material liabilities recorded for any indemnifications.

APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies related to power purchase and sale activity pursuant to the SIA.  PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.
 
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Master Lease Agreements

The Registrant Subsidiaries lease certain equipment under master lease agreements.  Under the 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.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.  As of June 30, 2012, 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
  
$
 2,798 
I&M
    
 2,302 
OPCo
    
 3,187 
PSO
    
 1,036 
SWEPCo
    
 2,415 

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 $15 million and $17 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2012.

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.  The maximum potential losses related to the guarantee are approximately $12 million and $13 million for I&M and SWEPCo, respectively, 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, I&M, OPCo, PSO and SWEPCo

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.  The court ordered all defendants to respond to the refiled complaints in October 2011.  In March 2012, the court granted the defendants’ motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations.  Plaintiffs appealed the decision to the Fifth Circuit Court of Appeals.  Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.
 
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Alaskan Villages’ Claims – Affecting APCo, 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.  The court heard oral argument in November 2011.  Management believes the action is without merit and will continue 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 $10 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.

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 cost approximately $400 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.  Due to the extensive lead time required to manufacture and install new turbine rotors, I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The installation of the new turbine rotors and other equipment occurred as planned during the fall 2011 refueling outage of Unit 1.
 
163
 
I&M maintains insurance through NEIL.  As of June 30, 2012, I&M recorded $64 million on its condensed balance sheet representing amounts under NEIL insurance policies.  Through June 30, 2012, I&M received payments from NEIL of $203 million for the cost incurred to date to repair the property damage and $185 million under an accidental outage policy.

The claims process with NEIL continues and includes a review of claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies, 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.  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 reduce future net income and cash flows and impact financial condition.

4.  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 plan 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, 2012 and 2011:

APCo
    
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Three Months Ended June 30,
  
Three Months Ended June 30,
 
2012 
  
2011 
  
2012 
  
2011 
 
(in thousands)
Service Cost
$
 1,891 
  
$
 1,800 
  
$
 1,347 
  
$
 1,246 
Interest Cost
  
 7,553 
    
 8,076 
    
 4,615 
    
 4,867 
Expected Return on Plan Assets
  
 (10,486)
    
 (10,458)
    
 (4,188)
    
 (4,496)
Amortization of Transition Obligation
  
 - 
    
 - 
    
 200 
    
 287 
Amortization of Prior Service Cost (Credit)
  
 119 
    
 229 
    
 (715)
    
 (43)
Amortization of Net Actuarial Loss
  
 5,084 
    
 4,144 
    
 2,632 
    
 1,459 
Net Periodic Benefit Cost
$
 4,161 
  
$
 3,791 
  
$
 3,891 
  
$
 3,320 

     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Six Months Ended June 30,
  
Six Months Ended June 30,
 
2012 
  
2011 
  
2012 
  
2011 
 
(in thousands)
Service Cost
$
 3,782 
  
$
 3,600 
  
$
 2,694 
  
$
 2,492 
Interest Cost
  
 15,106 
    
 16,146 
    
 9,231 
    
 9,734 
Expected Return on Plan Assets
  
 (20,972)
    
 (20,916)
    
 (8,376)
    
 (8,992)
Amortization of Transition Obligation
  
 - 
    
 - 
    
 400 
    
 573 
Amortization of Prior Service Cost (Credit)
  
 238 
    
 458 
    
 (1,431)
    
 (86)
Amortization of Net Actuarial Loss
  
 10,169 
    
 8,285 
    
 5,263 
    
 2,914 
Net Periodic Benefit Cost
$
 8,323 
  
$
 7,573 
  
$
 7,781 
  
$
 6,635 

 
164
 
I&M
    
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Three Months Ended June 30,
  
Three Months Ended June 30,
 
2012 
  
2011 
  
2012 
  
2011 
 
(in thousands)
Service Cost
$
 2,477 
  
$
 2,365 
  
$
 1,655 
  
$
 1,529 
Interest Cost
  
 6,561 
    
 6,934 
    
 3,197 
    
 3,402 
Expected Return on Plan Assets
  
 (9,392)
    
 (9,214)
    
 (3,212)
    
 (3,471)
Amortization of Transition Obligation
  
 - 
    
 - 
    
 33 
    
 47 
Amortization of Prior Service Cost (Credit)
  
 102 
    
 186 
    
 (596)
    
 (59)
Amortization of Net Actuarial Loss
  
 4,393 
    
 3,538 
    
 1,763 
    
 892 
Net Periodic Benefit Cost
$
 4,141 
  
$
 3,809 
  
$
 2,840 
  
$
 2,340 

     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Six Months Ended June 30,
  
Six Months Ended June 30,
 
2012 
  
2011 
  
2012 
  
2011 
 
(in thousands)
Service Cost
$
 4,954 
  
$
 4,723 
  
$
 3,310 
  
$
 3,059 
Interest Cost
  
 13,122 
    
 13,863 
    
 6,393 
    
 6,805 
Expected Return on Plan Assets
  
 (18,783)
    
 (18,428)
    
 (6,423)
    
 (6,943)
Amortization of Transition Obligation
  
 - 
    
 - 
    
 66 
    
 94 
Amortization of Prior Service Cost (Credit)
  
 204 
    
 372 
    
 (1,192)
    
 (118)
Amortization of Net Actuarial Loss
  
 8,785 
    
 7,072 
    
 3,525 
    
 1,783 
Net Periodic Benefit Cost
$
 8,282 
  
$
 7,602 
  
$
 5,679 
  
$
 4,680 

OPCo
    
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Three Months Ended June 30,
  
Three Months Ended June 30,
 
2012 
  
2011 
  
2012 
  
2011 
 
(in thousands)
Service Cost
$
 2,751 
  
$
 2,558 
  
$
 2,187 
  
$
 1,956 
Interest Cost
  
 11,299 
    
 12,098 
    
 6,048 
    
 6,373 
Expected Return on Plan Assets
  
 (17,101)
    
 (16,367)
    
 (5,639)
    
 (6,127)
Amortization of Transition Obligation
  
 - 
    
 - 
    
 26 
    
 38 
Amortization of Prior Service Cost (Credit)
  
 185 
    
 368 
    
 (968)
    
 (54)
Amortization of Net Actuarial Loss
  
 7,610 
    
 6,214 
    
 3,417 
    
 1,845 
Net Periodic Benefit Cost
$
 4,744 
  
$
 4,871 
  
$
 5,071 
  
$
 4,031 

     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Six Months Ended June 30,
  
Six Months Ended June 30,
 
2012 
  
2011 
  
2012 
  
2011 
 
(in thousands)
Service Cost
$
 5,502 
  
$
 5,115 
  
$
 4,374 
  
$
 3,913 
Interest Cost
  
 22,597 
    
 24,176 
    
 12,095 
    
 12,748 
Expected Return on Plan Assets
  
 (34,201)
    
 (32,733)
    
 (11,278)
    
 (12,256)
Amortization of Transition Obligation
  
 - 
    
 - 
    
 52 
    
 75 
Amortization of Prior Service Cost (Credit)
  
 371 
    
 736 
    
 (1,936)
    
 (107)
Amortization of Net Actuarial Loss
  
 15,220 
    
 12,414 
    
 6,834 
    
 3,649 
Net Periodic Benefit Cost
$
 9,489 
  
$
 9,708 
  
$
 10,141 
  
$
 8,022 

 
165
 
PSO
    
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Three Months Ended June 30,
  
Three Months Ended June 30,
 
2012 
  
2011 
  
2012 
  
2011 
 
(in thousands)
Service Cost
$
 1,488 
  
$
 1,442 
  
$
 709 
  
$
 656 
Interest Cost
  
 3,075 
    
 3,338 
    
 1,450 
    
 1,511 
Expected Return on Plan Assets
  
 (4,504)
    
 (4,366)
    
 (1,481)
    
 (1,566)
Amortization of Prior Service Credit
  
 (237)
    
 (239)
    
 (269)
    
 (19)
Amortization of Net Actuarial Loss
  
 2,051 
    
 1,700 
    
 797 
    
 388 
Net Periodic Benefit Cost
$
 1,873 
  
$
 1,875 
  
$
 1,206 
  
$
 970 

     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Six Months Ended June 30,
  
Six Months Ended June 30,
 
2012 
  
2011 
  
2012 
  
2011 
 
(in thousands)
Service Cost
$
 2,976 
  
$
 2,880 
  
$
 1,418 
  
$
 1,311 
Interest Cost
  
 6,150 
    
 6,643 
    
 2,899 
    
 3,023 
Expected Return on Plan Assets
  
 (9,008)
    
 (8,732)
    
 (2,961)
    
 (3,132)
Amortization of Prior Service Credit
  
 (474)
    
 (475)
    
 (539)
    
 (38)
Amortization of Net Actuarial Loss
  
 4,103 
    
 3,378 
    
 1,594 
    
 776 
Net Periodic Benefit Cost
$
 3,747 
  
$
 3,694 
  
$
 2,411 
  
$
 1,940 

SWEPCo
    
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Three Months Ended June 30,
  
Three Months Ended June 30,
 
2012 
  
2011 
  
2012 
  
2011 
 
(in thousands)
Service Cost
$
 1,774 
  
$
 1,644 
  
$
 831 
  
$
 757 
Interest Cost
  
 3,135 
    
 3,348 
    
 1,668 
    
 1,743 
Expected Return on Plan Assets
  
 (4,716)
    
 (4,595)
    
 (1,698)
    
 (1,800)
Amortization of Prior Service Cost (Credit)
  
 (199)
    
 (200)
    
 (233)
    
 64 
Amortization of Net Actuarial Loss
  
 2,082 
    
 1,700 
    
 914 
    
 446 
Net Periodic Benefit Cost
$
 2,076 
  
$
 1,897 
  
$
 1,482 
  
$
 1,210 

     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Six Months Ended June 30,
  
Six Months Ended June 30,
 
2012 
  
2011 
  
2012 
  
2011 
 
(in thousands)
Service Cost
$
 3,549 
  
$
 3,286 
  
$
 1,662 
  
$
 1,514 
Interest Cost
  
 6,269 
    
 6,666 
    
 3,336 
    
 3,485 
Expected Return on Plan Assets
  
 (9,433)
    
 (9,190)
    
 (3,397)
    
 (3,600)
Amortization of Prior Service Cost (Credit)
  
 (397)
    
 (398)
    
 (466)
    
 129 
Amortization of Net Actuarial Loss
  
 4,165 
    
 3,380 
    
 1,829 
    
 892 
Net Periodic Benefit Cost
$
 4,153 
  
$
 3,744 
  
$
 2,964 
  
$
 2,420 

5.  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.
 
166
 
6.  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 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.
 
167
 
The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of June 30, 2012 and December 31, 2011:

Notional Volume of Derivative Instruments
June 30, 2012
                                       
Primary Risk
  
Unit of
                              
Exposure
  
Measure
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
           
(in thousands)
Commodity:
                                  
 
Power
  
MWHs
    
 179,238 
    
 126,489 
    
 264,309 
    
 35 
    
 44 
 
Coal
  
Tons
    
 2,745 
    
 1,842 
    
 6,337 
    
 1,915 
    
 2,857 
 
Natural Gas
  
MMBtus
    
 12,501 
    
 8,793 
    
 18,435 
    
 78 
    
 98 
 
Heating Oil and
                                  
   
Gasoline
  
Gallons
    
 667 
    
 348 
    
 823 
    
 372 
    
 357 
 
Interest Rate
  
USD
  
$
 36,230 
  
$
 25,484 
  
$
 53,426 
  
$
 - 
  
$
 - 
                                       
Interest Rate and
                                  
 
Foreign Currency
  
USD
  
$
 - 
  
$
 200,000 
  
$
 - 
  
$
 - 
  
$
 - 
                                       
Notional Volume of Derivative Instruments
December 31, 2011
                                       
Primary Risk
  
Unit of
                              
Exposure
  
Measure
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
           
(in thousands)
Commodity:
                                  
 
Power
  
MWHs
    
 169,459 
    
 109,326 
    
 229,468 
    
 39 
    
 49 
 
Coal
  
Tons
    
 3,714 
    
 1,920 
    
 8,337 
    
 3,574 
    
 2,974 
 
Natural Gas
  
MMBtus
    
 7,923 
    
 5,081 
    
 10,728 
    
 115 
    
 145 
 
Heating Oil and
                                  
   
Gasoline
  
Gallons
    
 1,057 
    
 525 
    
 1,254 
    
 618 
    
 569 
 
Interest Rate
  
USD
  
$
 31,029 
  
$
 19,890 
  
$
 42,093 
  
$
 175 
  
$
 203 
                                       
Interest Rate and
                                  
 
Foreign Currency
  
USD
  
$
 - 
  
$
 200,000 
  
$
 - 
  
$
 - 
  
$
 200,069 

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.

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 activities as “Commodity.”  The Registrant Subsidiaries do not hedge all fuel price risk.
 
168
 
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 future borrowings of fixed-rate debt.  The forecasted 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 condensed 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.

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, 2012 and December 31, 2011 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, 2012
  
December 31, 2011
     
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
  
$
 2,664 
  
$
 19,667 
  
$
 4,291 
  
$
 28,964 
I&M
    
 1,874 
    
 13,793 
    
 2,752 
    
 18,547 
OPCo
    
 3,929 
    
 28,948 
    
 5,810 
    
 39,183 
PSO
    
 30 
    
 136 
    
 53 
    
 130 
SWEPCo
    
 37 
    
 133 
    
 66 
    
 124 

 
169
 
The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of June 30, 2012 and December 31, 2011:

Fair Value of Derivative Instruments
June 30, 2012
                                 
APCo
                              
     
Risk
                
     
Management
                
     
Contracts
  
Hedging Contracts
        
               
Interest Rate
        
             
and Foreign
        
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Other (b)
  
Total
     
(in thousands)
Current Risk Management Assets
  
$
252,825 
  
$
979 
  
$
- 
  
$
(211,963)
  
$
41,841 
Long-term Risk Management Assets
    
112,302 
    
236 
    
- 
    
(67,862)
    
44,676 
Total Assets
    
365,127 
    
1,215 
    
- 
    
(279,825)
    
86,517 
                                 
Current Risk Management Liabilities
    
243,424 
    
3,363 
    
- 
    
(223,751)
    
23,036 
Long-term Risk Management Liabilities
    
95,932 
    
660 
    
- 
    
(73,954)
    
22,638 
Total Liabilities
    
339,356 
    
4,023 
    
- 
    
(297,705)
    
45,674 
                                 
Total MTM Derivative Contract Net
                              
 
Assets (Liabilities)
  
$
25,771 
  
$
(2,808)
  
$
- 
  
$
17,880 
  
$
40,843 
                                 
Fair Value of Derivative Instruments
December 31, 2011
                                 
APCo
                              
     
Risk
                
     
Management
                
     
Contracts
  
Hedging Contracts
        
               
Interest Rate
        
             
and Foreign
        
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Other (b)
  
Total
     
(in thousands)
Current Risk Management Assets
  
$
232,784 
  
$
1,040 
  
$
- 
  
$
(194,179)
  
$
39,645 
Long-term Risk Management Assets
    
99,751 
    
90 
    
- 
    
(60,615)
    
39,226 
Total Assets
    
332,535 
    
1,130 
    
- 
    
(254,794)
    
78,871 
                                 
Current Risk Management Liabilities
    
235,354 
    
2,767 
    
- 
    
(211,515)
    
26,606 
Long-term Risk Management Liabilities
    
82,058 
    
350 
    
- 
    
(69,485)
    
12,923 
Total Liabilities
    
317,412 
    
3,117 
    
- 
    
(281,000)
    
39,529 
                                 
Total MTM Derivative Contract Net
                              
 
Assets (Liabilities)
  
$
15,123 
  
$
(1,987)
  
$
- 
  
$
26,206 
  
$
39,342 

 
170
 

Fair Value of Derivative Instruments
June 30, 2012
                                 
I&M
                              
     
Risk
                
     
Management
                
     
Contracts
  
Hedging Contracts
        
               
Interest Rate
        
             
and Foreign
        
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Other (b)
  
Total
     
(in thousands)
Current Risk Management Assets
  
$
186,932 
  
$
689 
  
$
- 
  
$
(148,563)
  
$
39,058 
Long-term Risk Management Assets
    
78,944 
    
166 
    
- 
    
(47,702)
    
31,408 
Total Assets
    
265,876 
    
855 
    
- 
    
(196,265)
    
70,466 
                                 
Current Risk Management Liabilities
    
170,637 
    
2,326 
    
18,095 
    
(156,819)
    
34,239 
Long-term Risk Management Liabilities
    
67,432 
    
458 
    
- 
    
(51,982)
    
15,908 
Total Liabilities
    
238,069 
    
2,784 
    
18,095 
    
(208,801)
    
50,147 
                                 
Total MTM Derivative Contract Net
                              
 
Assets (Liabilities)
  
$
27,807 
  
$
(1,929)
  
$
(18,095)
  
$
12,536 
  
$
20,319 
                                 
Fair Value of Derivative Instruments
December 31, 2011
                                 
I&M
                              
     
Risk
                
     
Management
                
     
Contracts
  
Hedging Contracts
        
               
Interest Rate
        
             
and Foreign
        
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Other (b)
  
Total
     
(in thousands)
Current Risk Management Assets
  
$
154,628 
  
$
667 
  
$
- 
  
$
(123,143)
  
$
32,152 
Long-term Risk Management Assets
    
68,047 
    
58 
    
- 
    
(38,743)
    
29,362 
Total Assets
    
222,675 
    
725 
    
- 
    
(161,886)
    
61,514 
                                 
Current Risk Management Liabilities
    
149,466 
    
1,747 
    
- 
    
(134,233)
    
16,980 
Long-term Risk Management Liabilities
    
52,441 
    
224 
    
10,637 
    
(44,431)
    
18,871 
Total Liabilities
    
201,907 
    
1,971 
    
10,637 
    
(178,664)
    
35,851 
                                 
Total MTM Derivative Contract Net
                              
 
Assets (Liabilities)
  
$
20,768 
  
$
(1,246)
  
$
(10,637)
  
$
16,778 
  
$
25,663 

 
171
 
 
Fair Value of Derivative Instruments
June 30, 2012
                                 
OPCo
                              
     
Risk
                
     
Management
                
     
Contracts
  
Hedging Contracts
        
               
Interest Rate
        
             
and Foreign
        
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Other (b)
  
Total
     
(in thousands)
Current Risk Management Assets
  
$
387,633 
  
$
1,445 
  
$
- 
  
$
(326,116)
  
$
62,962 
Long-term Risk Management Assets
    
166,799 
    
347 
    
- 
    
(100,856)
    
66,290 
Total Assets
    
554,432 
    
1,792 
    
- 
    
(426,972)
    
129,252 
                                 
Current Risk Management Liabilities
    
373,685 
    
4,906 
    
- 
    
(343,450)
    
35,141 
Long-term Risk Management Liabilities
    
142,621 
    
966 
    
- 
    
(109,834)
    
33,753 
Total Liabilities
    
516,306 
    
5,872 
    
- 
    
(453,284)
    
68,894 
                                 
Total MTM Derivative Contract Net
                              
 
Assets (Liabilities)
  
$
38,126 
  
$
(4,080)
  
$
- 
  
$
26,312 
  
$
60,358 
                                 
Fair Value of Derivative Instruments
December 31, 2011
                                 
OPCo
                              
     
Risk
                
     
Management
                
     
Contracts
  
Hedging Contracts
        
               
Interest Rate
        
             
and Foreign
        
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Other (b)
  
Total
     
(in thousands)
Current Risk Management Assets
  
$
325,904 
  
$
1,409 
  
$
- 
  
$
(273,020)
  
$
54,293 
Long-term Risk Management Assets
    
136,519 
    
122 
    
- 
    
(83,027)
    
53,614 
Total Assets
    
462,423 
    
1,531 
    
- 
    
(356,047)
    
107,907 
                                 
Current Risk Management Liabilities
    
329,307 
    
3,712 
    
- 
    
(296,458)
    
36,561 
Long-term Risk Management Liabilities
    
112,454 
    
474 
    
- 
    
(95,038)
    
17,890 
Total Liabilities
    
441,761 
    
4,186 
    
- 
    
(391,496)
    
54,451 
                                 
Total MTM Derivative Contract Net
                              
 
Assets (Liabilities)
  
$
20,662 
  
$
(2,655)
  
$
- 
  
$
35,449 
  
$
53,456 

 
172
 
 
Fair Value of Derivative Instruments
June 30, 2012
                                 
PSO
                              
     
Risk
                
     
Management
                
     
Contracts
  
Hedging Contracts
        
               
Interest Rate
        
             
and Foreign
        
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Other (b)
  
Total
     
(in thousands)
Current Risk Management Assets
  
$
4,961 
  
$
- 
  
$
- 
  
$
(4,369)
  
$
592 
Long-term Risk Management Assets
    
383 
    
- 
    
- 
    
(252)
    
131 
Total Assets
    
5,344 
    
- 
    
- 
    
(4,621)
    
723 
                                 
Current Risk Management Liabilities
    
8,987 
    
120 
    
- 
    
(4,456)
    
4,651 
Long-term Risk Management Liabilities
    
2,740 
    
21 
    
- 
    
(271)
    
2,490 
Total Liabilities
    
11,727 
    
141 
    
- 
    
(4,727)
    
7,141 
                                 
Total MTM Derivative Contract Net
                              
 
Assets (Liabilities)
  
$
(6,383)
  
$
(141)
  
$
- 
  
$
106 
  
$
(6,418)
                                 
Fair Value of Derivative Instruments
December 31, 2011
                                 
PSO
                              
     
Risk
                
     
Management
                
     
Contracts
  
Hedging Contracts
        
               
Interest Rate
        
             
and Foreign
        
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Other (b)
  
Total
     
(in thousands)
Current Risk Management Assets
  
$
6,980 
  
$
- 
  
$
- 
  
$
(6,415)
  
$
565 
Long-term Risk Management Assets
    
914 
    
- 
    
- 
    
(600)
    
314 
Total Assets
    
7,894 
    
- 
    
- 
    
(7,015)
    
879 
                                 
Current Risk Management Liabilities
    
7,665 
    
107 
    
- 
    
(6,492)
    
1,280 
Long-term Risk Management Liabilities
    
1,930 
    
- 
    
- 
    
(600)
    
1,330 
Total Liabilities
    
9,595 
    
107 
    
- 
    
(7,092)
    
2,610 
                                 
Total MTM Derivative Contract Net
                              
 
Assets (Liabilities)
  
$
(1,701)
  
$
(107)
  
$
- 
  
$
77 
  
$
(1,731)

 
173
 

Fair Value of Derivative Instruments
June 30, 2012
                                   
SWEPCo
                              
   
Risk
                
   
Management
                
   
Contracts
  
Hedging Contracts
        
             
Interest Rate
        
           
and Foreign
        
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Other (b)
  
Total
   
(in thousands)
Current Risk Management Assets
  
$
13,572 
  
$
- 
  
$
- 
  
$
(12,275)
  
$
1,297 
Long-term Risk Management Assets
    
1,074 
    
- 
    
- 
    
(706)
    
368 
Total Assets
    
14,646 
    
- 
    
- 
    
(12,981)
    
1,665 
                               
Current Risk Management Liabilities
    
20,246 
    
115 
    
- 
    
(12,352)
    
8,009 
Long-term Risk Management Liabilities
    
1,039 
    
21 
    
- 
    
(725)
    
335 
Total Liabilities
    
21,285 
    
136 
    
- 
    
(13,077)
    
8,344 
                               
Total MTM Derivative Contract Net
                              
 
Assets (Liabilities)
  
$
(6,639)
  
$
(136)
  
$
- 
  
$
96 
  
$
(6,679)
                               
Fair Value of Derivative Instruments
December 31, 2011
                               
SWEPCo
                              
   
Risk
                
   
Management
                
   
Contracts
  
Hedging Contracts
        
             
Interest Rate
        
           
and Foreign
        
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Other (b)
  
Total
   
(in thousands)
Current Risk Management Assets
  
$
6,327 
  
$
- 
  
$
3 
  
$
(5,885)
  
$
445 
Long-term Risk Management Assets
    
818 
    
- 
    
- 
    
(536)
    
282 
Total Assets
    
7,145 
    
- 
    
3 
    
(6,421)
    
727 
                               
Current Risk Management Liabilities
    
11,062 
    
97 
    
19,143 
    
(5,943)
    
24,359 
Long-term Risk Management Liabilities
    
757 
    
- 
    
- 
    
(536)
    
221 
Total Liabilities
    
11,819 
    
97 
    
19,143 
    
(6,479)
    
24,580 
                               
Total MTM Derivative Contract Net
                              
 
Assets (Liabilities)
  
$
(4,674)
  
$
(97)
  
$
(19,140)
  
$
58 
  
$
(23,853)
 
 (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 de-designated risk management contracts.

 
174
 
The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and six months ended June 30, 2012 and 2011:

 
Amount of Gain (Loss) Recognized on
 
Risk Management Contracts
 
For the Three Months Ended June 30, 2012
   
 
Location of Gain (Loss)
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
         
(in thousands)
 
Electric Generation, Transmission and
                              
   
Distribution Revenues
  
$
 (599)
  
$
 2,579 
  
$
 2,538 
  
$
 165 
  
$
 303 
 
Sales to AEP Affiliates
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
 
Fuel and Other Consumables Used for
                              
   
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
 
Regulatory Assets (a)
    
 (3,796)
    
 (2,905)
    
 (8,895)
    
 (757)
    
 (364)
 
Regulatory Liabilities (a)
    
 4,711 
    
 392 
    
 7,178 
    
 (26)
    
 (27)
 
Total Gain (Loss) on Risk Management
                              
   
Contracts
  
$
 316 
  
$
 66 
  
$
 821 
  
$
 (618)
  
$
 (88)
                                     
 
Amount of Gain (Loss) Recognized on
 
Risk Management Contracts
 
For the Three Months Ended June 30, 2011
   
 
Location of Gain (Loss)
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
         
(in thousands)
 
Electric Generation, Transmission and
                              
   
Distribution Revenues
  
$
 883 
  
$
 3,702 
  
$
 11,564 
  
$
 539 
  
$
 403 
 
Sales to AEP Affiliates
    
 13 
    
 6 
    
 13 
    
 (1)
    
 (1)
 
Fuel and Other Consumables Used for
                              
   
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
 
Regulatory Assets (a)
    
 (150)
    
 (1,018)
    
 (4,603)
    
 644 
    
 404 
 
Regulatory Liabilities (a)
    
 4,142 
    
 (1,077)
    
 - 
    
 461 
    
 692 
 
Total Gain (Loss) on Risk Management
                              
   
Contracts
  
$
 4,888 
  
$
 1,613 
  
$
 6,974 
  
$
 1,643 
  
$
 1,498 

 
175
 
 
Amount of Gain (Loss) Recognized on
 
Risk Management Contracts
 
For the Six Months Ended June 30, 2012
   
 
Location of Gain (Loss)
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
       
(in thousands)
 
Electric Generation, Transmission and
                              
   
Distribution Revenues
  
$
 (926)
  
$
 5,392 
  
$
 11,031 
  
$
 160 
  
$
 252 
 
Sales to AEP Affiliates
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
 
Fuel and Other Consumables Used for
                              
   
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
 
Regulatory Assets (a)
    
 (7,277)
    
 (6,015)
    
 (12,026)
    
 (5,958)
    
 (7,092)
 
Regulatory Liabilities (a)
    
 11,120 
    
 7,118 
    
 7,178 
    
 1 
    
 (5)
 
Total Gain (Loss) on Risk Management
                              
   
Contracts
  
$
 2,917 
  
$
 6,495 
  
$
 6,183 
  
$
 (5,797)
  
$
 (6,845)
                                   
 
Amount of Gain (Loss) Recognized on
 
Risk Management Contracts
 
For the Six Months Ended June 30, 2011
   
 
Location of Gain (Loss)
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
       
(in thousands)
 
Electric Generation, Transmission and
                              
   
Distribution Revenues
  
$
 2,699 
  
$
 9,117 
  
$
 22,154 
  
$
 658 
  
$
 526 
 
Sales to AEP Affiliates
    
 33 
    
 23 
    
 45 
    
 - 
    
 - 
 
Fuel and Other Consumables Used for
                              
   
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
 
Regulatory Assets (a)
    
 223 
    
 115 
    
 (4,208)
    
 276 
    
 2,046 
 
Regulatory Liabilities (a)
    
 10,896 
    
 (1,664)
    
 (105)
    
 853 
    
 1,032 
 
Total Gain (Loss) on Risk Management
                              
   
Contracts
  
$
 13,851 
  
$
 7,591 
  
$
 17,886 
  
$
 1,787 
  
$
 3,604 
                                   
 
(a)   Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current
 
        or noncurrent on the condensed 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 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.”
 
176
 
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, 2012 and 2011, the Registrant Subsidiaries did not designate 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 and natural gas 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, 2012 and 2011, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline 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, 2012 and 2011, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur.  During the three and six months ended June 30, 2012, I&M and SWEPCo designated interest rate derivatives as cash flow hedges.  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.

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, 2012 and 2011, SWEPCo designated foreign currency derivatives as cash flow hedges.

During the three and six months ended June 30, 2012 and 2011, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.
 
177
 
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, 2012 and 2011.  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, 2012
                                     
Commodity Contracts
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
   
(in thousands)
Balance in AOCI as of March 31, 2012
  
$
 (2,117)
  
$
 (1,508)
  
$
 (3,149)
  
$
 67 
  
$
 66 
Changes in Fair Value Recognized in AOCI
    
 (403)
    
 (234)
    
 (525)
    
 (155)
    
 (149)
Amount of (Gain) or Loss Reclassified
                              
 
from AOCI to Statement of Income/within
                              
 
Balance Sheet:
                              
   
Electric Generation, Transmission, and
                              
     
Distribution Revenues
    
 (3)
    
 (9)
    
 (24)
    
 - 
    
 - 
   
Fuel and Other Consumables Used for
                              
     
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
   
Purchased Electricity for Resale
    
 157 
    
 419 
    
 1,099 
    
 - 
    
 - 
   
Other Operation Expense
    
 (14)
    
 (8)
    
 (19)
    
 (9)
    
 (7)
   
Maintenance Expense
    
 (6)
    
 (3)
    
 (8)
    
 (2)
    
 (2)
   
Property, Plant and Equipment
    
 (10)
    
 (6)
    
 (13)
    
 (3)
    
 (5)
   
Regulatory Assets (a)
    
 576 
    
 103 
    
 - 
    
 - 
    
 - 
   
Regulatory Liabilities (a)
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
Balance in AOCI as of June 30, 2012
  
$
 (1,820)
  
$
 (1,246)
  
$
 (2,639)
  
$
 (102)
  
$
 (97)
                                     
Interest Rate and
                              
Foreign Currency Contracts
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
         
(in thousands)
Balance in AOCI as of March 31, 2012
  
$
 1,293 
  
$
 (11,320)
  
$
 9,114 
  
$
 7,029 
  
$
 (17,365)
Changes in Fair Value Recognized in AOCI
    
 - 
    
 (7,844)
    
 - 
    
 - 
    
 (1)
Amount of (Gain) or Loss Reclassified
                              
 
from AOCI to Statement of Income/within
                              
 
Balance Sheet:
                              
   
Depreciation and Amortization
                              
     
Expense
    
 - 
    
 - 
    
 1 
    
 - 
    
 - 
   
Other Operation Expense
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
   
Interest Expense
    
 269 
    
 149 
    
 (341)
    
 (190)
    
 560 
Balance in AOCI as of June 30, 2012
  
$
 1,562 
  
$
 (19,015)
  
$
 8,774 
  
$
 6,839 
  
$
 (16,806)
                                     
Total Contracts
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
         
(in thousands)
Balance in AOCI as of March 31, 2012
  
$
 (824)
  
$
 (12,828)
  
$
 5,965 
  
$
 7,096 
  
$
 (17,299)
Changes in Fair Value Recognized in AOCI
    
 (403)
    
 (8,078)
    
 (525)
    
 (155)
    
 (150)
Amount of (Gain) or Loss Reclassified
                              
 
from AOCI to Statement of Income/within
                              
 
Balance Sheet:
                              
   
Electric Generation, Transmission, and
                              
     
Distribution Revenues
    
 (3)
    
 (9)
    
 (24)
    
 - 
    
 - 
   
Fuel and Other Consumables Used for
                              
     
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
   
Purchased Electricity for Resale
    
 157 
    
 419 
    
 1,099 
    
 - 
    
 - 
   
Other Operation Expense
    
 (14)
    
 (8)
    
 (19)
    
 (9)
    
 (7)
   
Maintenance Expense
    
 (6)
    
 (3)
    
 (8)
    
 (2)
    
 (2)
   
Depreciation and Amortization
                              
     
Expense
    
 - 
    
 - 
    
 1 
    
 - 
    
 - 
   
Interest Expense
    
 269 
    
 149 
    
 (341)
    
 (190)
    
 560 
   
Property, Plant and Equipment
    
 (10)
    
 (6)
    
 (13)
    
 (3)
    
 (5)
   
Regulatory Assets (a)
    
 576 
    
 103 
    
 - 
    
 - 
    
 - 
   
Regulatory Liabilities (a)
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
Balance in AOCI as of June 30, 2012
  
$
 (258)
  
$
 (20,261)
  
$
 6,135 
  
$
 6,737 
  
$
 (16,903)

 
178
 

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2011
 
Commodity Contracts
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
   
(in thousands)
Balance in AOCI as of March 31, 2011
  
$
 238 
  
$
 101 
  
$
 269 
  
$
 264 
  
$
 244 
Changes in Fair Value Recognized in AOCI
    
 (55)
    
 (25)
    
 (64)
    
 (32)
    
 (26)
Amount of (Gain) or Loss Reclassified
                              
 
from AOCI to Statement of Income/within
                              
 
Balance Sheet:
                              
   
Electric Generation, Transmission, and
                              
     
Distribution Revenues
    
 175 
    
 396 
    
 1,060 
    
 - 
    
 - 
   
Fuel and Other Consumables Used for
                              
     
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
   
Purchased Electricity for Resale
    
 (41)
    
 (92)
    
 (246)
    
 - 
    
 - 
   
Other Operation Expense
    
 (31)
    
 (28)
    
 (60)
    
 (34)
    
 (33)
   
Maintenance Expense
    
 (65)
    
 (22)
    
 (51)
    
 (22)
    
 (24)
   
Property, Plant and Equipment
    
 (57)
    
 (28)
    
 (71)
    
 (36)
    
 (29)
   
Regulatory Assets (a)
    
 505 
    
 76 
    
 - 
    
 - 
    
 - 
   
Regulatory Liabilities (a)
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
Balance in AOCI as of June 30, 2011
  
$
 669 
  
$
 378 
  
$
 837 
  
$
 140 
  
$
 132 
                                     
Interest Rate and
                              
Foreign Currency Contracts
  
APCo
  
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 Statement of Income/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
  
I&M
  
OPCo
  
PSO
  
SWEPCo
         
(in thousands)
Balance in AOCI as of March 31, 2011
  
$
 455 
  
$
 (8,154)
  
$
 10,742 
  
$
 8,051 
  
$
 (3,814)
Changes in Fair Value Recognized in AOCI
    
 (55)
    
 (25)
    
 (64)
    
 (32)
    
 768 
Amount of (Gain) or Loss Reclassified
                              
 
from AOCI to Statement of Income/within
                              
 
Balance Sheet:
                              
   
Electric Generation, Transmission, and
                              
     
Distribution Revenues
    
 175 
    
 396 
    
 1,060 
    
 - 
    
 - 
   
Fuel and Other Consumables Used for
                              
     
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
   
Purchased Electricity for Resale
    
 (41)
    
 (92)
    
 (246)
    
 - 
    
 - 
   
Other Operation Expense
    
 (31)
    
 (28)
    
 (60)
    
 (34)
    
 (33)
   
Maintenance Expense
    
 (65)
    
 (22)
    
 (51)
    
 (22)
    
 (24)
   
Depreciation and Amortization
                              
     
Expense
    
 - 
    
 - 
    
 1 
    
 - 
    
 - 
   
Interest Expense
    
 269 
    
 251 
    
 (341)
    
 (189)
    
 207 
   
Property, Plant and Equipment
    
 (57)
    
 (28)
    
 (71)
    
 (36)
    
 (29)
   
Regulatory Assets (a)
    
 505 
    
 76 
    
 - 
    
 - 
    
 - 
   
Regulatory Liabilities (a)
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
Balance in AOCI as of June 30, 2011
  
$
 1,155 
  
$
 (7,626)
  
$
 10,970 
  
$
 7,738 
  
$
 (2,925)

 
179
 

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2012
 
Commodity Contracts
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
   
(in thousands)
Balance in AOCI as of December 31, 2011
  
$
 (1,309)
  
$
 (819)
  
$
 (1,748)
  
$
 (69)
  
$
 (62)
Changes in Fair Value Recognized in AOCI
    
 (2,248)
    
 (1,628)
    
 (3,402)
    
 (16)
    
 (17)
Amount of (Gain) or Loss Reclassified
                              
 
from AOCI to Income Statement/within
                              
 
Balance Sheet:
                              
   
Electric Generation, Transmission, and
                              
     
Distribution Revenues
    
 (3)
    
 (9)
    
 (24)
    
 - 
    
 - 
   
Fuel and Other Consumables Used for
                              
     
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
   
Purchased Electricity for Resale
    
 376 
    
 986 
    
 2,585 
    
 - 
    
 - 
   
Other Operation Expense
    
 (16)
    
 (10)
    
 (24)
    
 (11)
    
 (9)
   
Maintenance Expense
    
 (9)
    
 (4)
    
 (10)
    
 (2)
    
 (3)
   
Property, Plant and Equipment
    
 (12)
    
 (7)
    
 (16)
    
 (4)
    
 (6)
   
Regulatory Assets (a)
    
 1,401 
    
 245 
    
 - 
    
 - 
    
 - 
   
Regulatory Liabilities (a)
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
Balance in AOCI as of June 30, 2012
  
$
 (1,820)
  
$
 (1,246)
  
$
 (2,639)
  
$
 (102)
  
$
 (97)
                                     
Interest Rate and
                              
Foreign Currency Contracts
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
         
(in thousands)
Balance in AOCI as of December 31, 2011
  
$
 1,024 
  
$
 (14,465)
  
$
 9,454 
  
$
 7,218 
  
$
 (15,462)
Changes in Fair Value Recognized in AOCI
    
 - 
    
 (4,848)
    
 - 
    
 - 
    
 (2,777)
Amount of (Gain) or Loss Reclassified
                              
 
from AOCI to Income Statement/within
                              
 
Balance Sheet:
                              
   
Depreciation and Amortization
                              
     
Expense
    
 - 
    
 - 
    
 2 
    
 - 
    
 - 
   
Other Operation Expense
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
   
Interest Expense
    
 538 
    
 298 
    
 (682)
    
 (379)
    
 1,433 
Balance in AOCI as of June 30, 2012
  
$
 1,562 
  
$
 (19,015)
  
$
 8,774 
  
$
 6,839 
  
$
 (16,806)
                                     
Total Contracts
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
         
(in thousands)
Balance in AOCI as of December 31, 2011
  
$
 (285)
  
$
 (15,284)
  
$
 7,706 
  
$
 7,149 
  
$
 (15,524)
Changes in Fair Value Recognized in AOCI
    
 (2,248)
    
 (6,476)
    
 (3,402)
    
 (16)
    
 (2,794)
Amount of (Gain) or Loss Reclassified
                              
 
from AOCI to Income Statement/within
                              
 
Balance Sheet:
                              
   
Electric Generation, Transmission, and
                              
     
Distribution Revenues
    
 (3)
    
 (9)
    
 (24)
    
 - 
    
 - 
   
Fuel and Other Consumables Used for
                              
     
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
   
Purchased Electricity for Resale
    
 376 
    
 986 
    
 2,585 
    
 - 
    
 - 
   
Other Operation Expense
    
 (16)
    
 (10)
    
 (24)
    
 (11)
    
 (9)
   
Maintenance Expense
    
 (9)
    
 (4)
    
 (10)
    
 (2)
    
 (3)
   
Depreciation and Amortization
                              
     
Expense
    
 - 
    
 - 
    
 2 
    
 - 
    
 - 
   
Interest Expense
    
 538 
    
 298 
    
 (682)
    
 (379)
    
 1,433 
   
Property, Plant and Equipment
    
 (12)
    
 (7)
    
 (16)
    
 (4)
    
 (6)
   
Regulatory Assets (a)
    
 1,401 
    
 245 
    
 - 
    
 - 
    
 - 
   
Regulatory Liabilities (a)
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
Balance in AOCI as of June 30, 2012
  
$
 (258)
  
$
 (20,261)
  
$
 6,135 
  
$
 6,737 
  
$
 (16,903)

 
180
 

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2011
                                     
Commodity Contracts
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
   
(in thousands)
Balance in AOCI as of December 31, 2010
  
$
 (273)
  
$
 (178)
  
$
 (364)
  
$
 88 
  
$
 82 
Changes in Fair Value Recognized in AOCI
    
 123 
    
 53 
    
 143 
    
 180 
    
 168 
Amount of (Gain) or Loss Reclassified
                              
 
from AOCI to Income Statement/within
                              
 
Balance Sheet:
                              
   
Electric Generation, Transmission, and
                              
     
Distribution Revenues
    
 171 
    
 386 
    
 1,034 
    
 - 
    
 - 
   
Fuel and Other Consumables Used for
                              
     
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
   
Purchased Electricity for Resale
    
 46 
    
 102 
    
 275 
    
 - 
    
 - 
   
Other Operation Expense
    
 (44)
    
 (37)
    
 (83)
    
 (47)
    
 (46)
   
Maintenance Expense
    
 (90)
    
 (32)
    
 (70)
    
 (29)
    
 (32)
   
Property, Plant and Equipment
    
 (80)
    
 (39)
    
 (98)
    
 (52)
    
 (40)
   
Regulatory Assets (a)
    
 816 
    
 123 
    
 - 
    
 - 
    
 - 
   
Regulatory Liabilities (a)
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
Balance in AOCI as of June 30, 2011
  
$
 669 
  
$
 378 
  
$
 837 
  
$
 140 
  
$
 132 
                                     
Interest Rate and
                              
Foreign Currency Contracts
  
APCo
  
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
  
I&M
  
OPCo
  
PSO
  
SWEPCo
         
(in thousands)
Balance in AOCI as of December 31, 2010
  
$
 (56)
  
$
 (8,685)
  
$
 10,449 
  
$
 8,494 
  
$
 (4,190)
Changes in Fair Value Recognized in AOCI
    
 (250)
    
 53 
    
 143 
    
 (296)
    
 969 
Amount of (Gain) or Loss Reclassified
                              
 
from AOCI to Income Statement/within
                              
 
Balance Sheet:
                              
   
Electric Generation, Transmission, and
                              
     
Distribution Revenues
    
 171 
    
 386 
    
 1,034 
    
 - 
    
 - 
   
Fuel and Other Consumables Used for
                              
     
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
   
Purchased Electricity for Resale
    
 46 
    
 102 
    
 275 
    
 - 
    
 - 
   
Other Operation Expense
    
 (44)
    
 (37)
    
 (83)
    
 (47)
    
 (46)
   
Maintenance Expense
    
 (90)
    
 (32)
    
 (70)
    
 (29)
    
 (32)
   
Depreciation and Amortization
                              
     
Expense
    
 - 
    
 - 
    
 2 
    
 - 
    
 - 
   
Interest Expense
    
 642 
    
 503 
    
 (682)
    
 (332)
    
 414 
   
Property, Plant and Equipment
    
 (80)
    
 (39)
    
 (98)
    
 (52)
    
 (40)
   
Regulatory Assets (a)
    
 816 
    
 123 
    
 - 
    
 - 
    
 - 
   
Regulatory Liabilities (a)
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
Balance in AOCI as of June 30, 2011
  
$
 1,155 
  
$
 (7,626)
  
$
 10,970 
  
$
 7,738 
  
$
 (2,925)
                                     
(a)
  
Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.

 
181
 
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of June 30, 2012 and December 31, 2011 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
June 30, 2012
 
     
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
  
$
 963 
  
$
 - 
  
$
 3,771 
  
$
 - 
  
$
 (1,820)
  
$
 1,562 
I&M
    
 677 
    
 - 
    
 2,606 
    
 18,095 
    
 (1,246)
    
 (19,015)
OPCo
    
 1,420 
    
 - 
    
 5,500 
    
 - 
    
 (2,639)
    
 8,774 
PSO
    
 - 
    
 - 
    
 141 
    
 - 
    
 (102)
    
 6,839 
SWEPCo
    
 - 
    
 - 
    
 136 
    
 - 
    
 (97)
    
 (16,806)

     
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
  
$
 (1,543)
  
$
 (1,021)
    
 23 
I&M
    
 (1,057)
    
 (938)
    
 23 
OPCo
    
 (2,236)
    
 1,359 
    
 23 
PSO
    
 (89)
    
 759 
    
 18 
SWEPCo
    
 (84)
    
 (2,369)
    
 18 

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 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
  
$
 431 
  
$
 - 
  
$
 2,418 
  
$
 - 
  
$
 (1,309)
  
$
 1,024 
I&M
    
 277 
    
 - 
    
 1,523 
    
 10,637 
    
 (819)
    
 (14,465)
OPCo
    
 584 
    
 - 
    
 3,239 
    
 - 
    
 (1,748)
    
 9,454 
PSO
    
 - 
    
 - 
    
 107 
    
 - 
    
 (69)
    
 7,218 
SWEPCo
    
 - 
    
 3 
    
 97 
    
 19,143 
    
 (62)
    
 (15,462)

 
Expected to be Reclassified to
  
 
Net Income During the Next
  
 
Twelve Months
  
     
Interest Rate
  
     
and Foreign
  
Company
Commodity
  
Currency
  
 
(in thousands)
  
APCo
   $ (1,140 )   $ (1,052 )
I&M
     (712 )     (595 )
OPCo
     (1,518 )     1,359  
PSO
     (70 )     759  
SWEPCo
     (63 )     (1,864 )

(a)
Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.

 
182
 
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.

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.  The Registrant Subsidiaries have not experienced 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, 2012 and December 31, 2011:

     
June 30, 2012
     
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
  
$
 1,929 
  
$
 2,664 
  
$
 2,664 
I&M
    
 1,357 
    
 1,874 
    
 1,874 
OPCo
    
 2,845 
    
 3,928 
    
 3,928 
PSO
    
 - 
    
 1,002 
    
 269 
SWEPCo
    
 - 
    
 1,263 
    
 339 

     
December 31, 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
  
$
 10,007 
  
$
 6,211 
  
$
 6,211 
I&M
    
 6,418 
    
 3,983 
    
 3,983 
OPCo
    
 13,550 
    
 8,410 
    
 8,410 
PSO
    
 - 
    
 856 
    
 414 
SWEPCo
    
 - 
    
 1,128 
    
 522 

As of June 30, 2012 and December 31, 2011, the Registrant Subsidiaries were not required to post any collateral.
 
183
 
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.  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, 2012 and December 31, 2011:

     
June 30, 2012
     
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
  
$
 92,276 
  
$
 2,294 
  
$
 37,533 
I&M
    
 83,000 
    
 1,613 
    
 44,495 
OPCo
    
 136,073 
    
 3,383 
    
 55,347 
PSO
    
 150 
    
 - 
    
 44 
SWEPCo
    
 189 
    
 - 
    
 55 
                     
     
December 31, 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
  
$
 76,868 
  
$
 8,107 
  
$
 27,603 
I&M
    
 59,936 
    
 5,200 
    
 28,339 
OPCo
    
 104,091 
    
 10,978 
    
 37,380 
PSO
    
 142 
    
 - 
    
 61 
SWEPCo
    
 19,322 
    
 - 
    
 19,220 

7.  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.

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
 
184
 
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.  The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market.   To a lesser extent, these contracts could be sensitive to volumetric estimates for some structured transactions.  However, a significant portion of the Level 3 volumetric contractual positions have been economically hedged which greatly limits potential earnings volatility.

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 management performs its 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, Other Cash Deposits and Cash and Cash Equivalents 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.  Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds.  Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  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.

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 classified as Level 2 measurement inputs.  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, 2012 and December 31, 2011 are summarized in the following table:

   
June 30, 2012
  
December 31, 2011
Company
  
Book Value
  
Fair Value
  
Book Value
  
Fair Value
   
(in thousands)
APCo
  
$
 3,677,116 
  
$
 4,380,840 
  
$
 3,726,251 
  
$
 4,431,912 
I&M
    
 2,131,501 
    
 2,402,581 
    
 2,057,675 
    
 2,339,344 
OPCo
    
 3,860,044 
    
 4,453,479 
    
 4,054,148 
    
 4,665,739 
PSO
    
 949,897 
    
 1,138,292 
    
 947,364 
    
 1,123,306 
SWEPCo
    
 2,047,676 
    
 2,315,719 
    
 1,728,637 
    
 2,019,094 

 
185
 
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.

The following is a summary of nuclear trust fund investments as of June 30, 2012 and December 31, 2011:

     
June 30, 2012
  
December 31, 2011
     
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
  
$
 15,826 
  
$
 - 
  
$
 - 
  
$
 18,229 
  
$
 - 
  
$
 - 
Fixed Income Securities:
                                    
 
United States Government
    
 643,542 
    
 104,394 
    
 (640)
    
 543,506 
    
 60,946 
    
 (547)
 
Corporate Debt
    
 44,354 
    
 5,113 
    
 (1,463)
    
 53,979 
    
 4,932 
    
 (1,536)
 
State and Local Government
    
 256,373 
    
 698 
    
 (1,182)
    
 329,986 
    
 (430)
    
 (2,236)
 
  Subtotal Fixed Income Securities
  
 944,269 
    
 110,205 
    
 (3,285)
    
 927,471 
    
 65,448 
    
 (4,319)
Equity Securities - Domestic
    
 697,407 
    
 257,975 
    
 (78,841)
    
 646,032 
    
 214,748 
    
 (79,536)
Spent Nuclear Fuel and
                                    
 
Decommissioning Trusts
  
$
 1,657,502 
  
$
 368,180 
  
$
 (82,126)
  
$
 1,591,732 
  
$
 280,196 
  
$
 (83,855)

 
186
 
The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2012 and 2011:

 
Three Months Ended June 30,
  
Six Months Ended June 30,
 
2012 
  
2011 
  
2012 
  
2011 
 
(in thousands)
Proceeds from Investment Sales
$
 182,179 
  
$
 176,927 
  
$
 516,579 
  
$
 464,688 
Purchases of Investments
  
 192,104 
    
 186,217 
    
 544,981 
    
 492,162 
Gross Realized Gains on Investment Sales
  
 3,380 
    
 7,392 
    
 4,932 
    
 12,405 
Gross Realized Losses on Investment Sales
  
 803 
    
 4,043 
    
 2,219 
    
 9,290 

The adjusted cost of debt securities was $834 million and $862 million as of June 30, 2012 and December 31, 2011, respectively.  The adjusted cost of equity securities was $440 million and $431 million as of June 30, 2012 and December 31, 2011, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2012 was as follows:

 
Fair Value
  
 
of Debt
  
 
Securities
  
 
(in thousands)
  
Within 1 year
   $ 39,580  
1 year – 5 years
     361,676  
5 years – 10 years
     315,547  
After 10 years
     227,466  
Total
   $ 944,269  

 
187
 
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, 2012 and December 31, 2011.  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, 2012
APCo
                  
   
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in thousands)
                               
Risk Management Assets
                            
Risk Management Commodity Contracts (a) (f)
$
 5,566 
  
$
 331,309 
  
$
 27,645 
  
$
 (279,843)
  
$
 84,677 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 1,186 
    
 29 
    
 (252)
    
 963 
De-designated Risk Management Contracts (b)
  
 - 
    
 - 
    
 - 
    
 877 
    
 877 
Total Risk Management Assets
$
 5,566 
  
$
 332,495 
  
$
 27,674 
  
$
 (279,218)
  
$
 86,517 
                               
Liabilities:
                            
                               
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (f)
$
 2,784 
  
$
 321,155 
  
$
 14,810 
  
$
 (296,846)
  
$
 41,903 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 4,023 
    
 - 
    
 (252)
    
 3,771 
Total Risk Management Liabilities
$
 2,784 
  
$
 325,178 
  
$
 14,810 
  
$
 (297,098)
  
$
 45,674 

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2011
APCo
                  
   
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in thousands)
                               
Risk Management Assets
                            
Risk Management Commodity Contracts (a) (f)
$
 4,680 
  
$
 302,128 
  
$
 25,423 
  
$
 (255,324)
  
$
 76,907 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 1,095 
    
 - 
    
 (664)
    
 431 
De-designated Risk Management Contracts (b)
  
 - 
    
 - 
    
 - 
    
 1,533 
    
 1,533 
Total Risk Management Assets
$
 4,680 
  
$
 303,223 
  
$
 25,423 
  
$
 (254,455)
  
$
 78,871 
                               
Liabilities:
                            
                               
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (f)
$
 2,535 
  
$
 291,194 
  
$
 23,379 
  
$
 (279,997)
  
$
 37,111 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 3,009 
    
 73 
    
 (664)
    
 2,418 
Total Risk Management Liabilities
$
 2,535 
  
$
 294,203 
  
$
 23,452 
  
$
 (280,661)
  
$
 39,529 

 
188
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2012
I&M
                  
     
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in thousands)
                                 
Risk Management Assets
                            
Risk Management Commodity Contracts (a) (f)
$
 3,915 
  
$
 242,091 
  
$
 19,445 
  
$
 (196,279)
  
$
 69,172 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 834 
    
 21 
    
 (178)
    
 677 
De-designated Risk Management Contracts (b)
  
 - 
    
 - 
    
 - 
    
 617 
    
 617 
Total Risk Management Assets
  
 3,915 
    
 242,925 
    
 19,466 
    
 (195,840)
    
 70,466 
                                 
Spent Nuclear Fuel and Decommissioning Trusts
                            
Cash and Cash Equivalents (d)
  
 - 
    
 3,984 
    
 - 
    
 11,842 
    
 15,826 
Fixed Income Securities:
                            
 
United States Government
  
 - 
    
 643,542 
    
 - 
    
 - 
    
 643,542 
 
Corporate Debt
  
 - 
    
 44,354 
    
 - 
    
 - 
    
 44,354 
 
State and Local Government
  
 - 
    
 256,373 
    
 - 
    
 - 
    
 256,373 
   
Subtotal Fixed Income Securities
  
 - 
    
 944,269 
    
 - 
    
 - 
    
 944,269 
Equity Securities - Domestic (e)
  
 697,407 
    
 - 
    
 - 
    
 - 
    
 697,407 
Total Spent Nuclear Fuel and Decommissioning Trusts
  
 697,407 
    
 948,253 
    
 - 
    
 11,842 
    
 1,657,502 
                                 
Total Assets
$
 701,322 
  
$
 1,191,178 
  
$
 19,466 
  
$
 (183,998)
  
$
 1,727,968 
                                 
Liabilities:
                            
                                 
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (f)
$
 1,958 
  
$
 225,269 
  
$
 10,417 
  
$
 (208,198)
  
$
 29,446 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 2,784 
    
 - 
    
 (178)
    
 2,606 
 
Interest Rate/Foreign Currency Hedges
  
 - 
    
 18,095 
    
 - 
    
 - 
    
 18,095 
Total Risk Management Liabilities
$
 1,958 
  
$
 246,148 
  
$
 10,417 
  
$
 (208,376)
  
$
 50,147 

 
189
 
   
Assets and Liabilities Measured at Fair Value on a Recurring Basis
   
December 31, 2011
I&M
                  
     
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in thousands)
                                 
Risk Management Assets
                            
Risk Management Commodity Contracts (a) (f)
$
 3,001 
  
$
 203,175 
  
$
 16,305 
  
$
 (162,227)
  
$
 60,254 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 702 
    
 - 
    
 (425)
    
 277 
De-designated Risk Management Contracts (b)
  
 - 
    
 - 
    
 - 
    
 983 
    
 983 
Total Risk Management Assets
  
 3,001 
    
 203,877 
    
 16,305 
    
 (161,669)
    
 61,514 
                                 
Spent Nuclear Fuel and Decommissioning Trusts
                            
Cash and Cash Equivalents (d)
  
 - 
    
 5,431 
    
 - 
    
 12,798 
    
 18,229 
Fixed Income Securities:
                            
 
United States Government
  
 - 
    
 543,506 
    
 - 
    
 - 
    
 543,506 
 
Corporate Debt
  
 - 
    
 53,979 
    
 - 
    
 - 
    
 53,979 
 
State and Local Government
  
 - 
    
 329,986 
    
 - 
    
 - 
    
 329,986 
   
Subtotal Fixed Income Securities
  
 - 
    
 927,471 
    
 - 
    
 - 
    
 927,471 
Equity Securities - Domestic (e)
  
 646,032 
    
 - 
    
 - 
    
 - 
    
 646,032 
Total Spent Nuclear Fuel and Decommissioning Trusts
  
 646,032 
    
 932,902 
    
 - 
    
 12,798 
    
 1,591,732 
                                 
Total Assets
$
 649,033 
  
$
 1,136,779 
  
$
 16,305 
  
$
 (148,871)
  
$
 1,653,246 
                                 
Liabilities:
                            
                                 
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (f)
$
 1,626 
  
$
 185,092 
  
$
 14,995 
  
$
 (178,022)
  
$
 23,691 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 1,901 
    
 47 
    
 (425)
    
 1,523 
 
Interest Rate/Foreign Currency Hedges
  
 - 
    
 10,637 
    
 - 
    
 - 
    
 10,637 
Total Risk Management Liabilities
$
 1,626 
  
$
 197,630 
  
$
 15,042 
  
$
 (178,447)
  
$
 35,851 

 
190
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
June 30, 2012
OPCo
                            
   
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in thousands)
                               
Other Cash Deposits (c)
$
 - 
  
$
 26 
  
$
 - 
  
$
 39 
  
$
 65 
                               
Risk Management Assets
                            
Risk Management Commodity Contracts (a) (f)
  
 8,207 
    
 504,483 
    
 40,766 
    
 (426,917)
    
 126,539 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 1,749 
    
 43 
    
 (372)
    
 1,420 
De-designated Risk Management Contracts (b)
  
 - 
    
 - 
    
 - 
    
 1,293 
    
 1,293 
Total Risk Management Assets
  
 8,207 
    
 506,232 
    
 40,809 
    
 (425,996)
    
 129,252 
                               
Total Assets
$
 8,207 
  
$
 506,258 
  
$
 40,809 
  
$
 (425,957)
  
$
 129,317 
                               
Liabilities:
                            
                               
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (f)
$
 4,106 
  
$
 489,384 
  
$
 21,840 
  
$
 (451,936)
  
$
 63,394 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 5,872 
    
 - 
    
 (372)
    
 5,500 
Total Risk Management Liabilities
$
 4,106 
  
$
 495,256 
  
$
 21,840 
  
$
 (452,308)
  
$
 68,894 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 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)
  
 6,339 
    
 421,249 
    
 34,425 
    
 (356,766)
    
 105,247 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 1,483 
    
 - 
    
 (899)
    
 584 
De-designated Risk Management Contracts (b)
  
 - 
    
 - 
    
 - 
    
 2,076 
    
 2,076 
Total Risk Management Assets
  
 6,339 
    
 422,732 
    
 34,425 
    
 (355,589)
    
 107,907 
                               
Total Assets
$
 6,365 
  
$
 422,732 
  
$
 34,425 
  
$
 (355,567)
  
$
 107,955 
                               
Liabilities:
                            
                               
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (f)
$
 3,433 
  
$
 406,259 
  
$
 31,659 
  
$
 (390,139)
  
$
 51,212 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 4,038 
    
 100 
    
 (899)
    
 3,239 
Total Risk Management Liabilities
$
 3,433 
  
$
 410,297 
  
$
 31,759 
  
$
 (391,038)
  
$
 54,451 

 
191
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
June 30, 2012
PSO
                  
   
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in thousands)
                               
Risk Management Assets
                            
Risk Management Commodity Contracts (a) (f)
$
 74 
  
$
 5,245 
  
$
 - 
  
$
 (4,596)
  
$
 723 
                               
Liabilities:
                            
                               
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (f)
$
 40 
  
$
 11,662 
  
$
 - 
  
$
 (4,702)
  
$
 7,000 
Cash Flow Hedges:
                            
 
Commodity Hedges
  
 - 
    
 141 
    
 - 
    
 - 
    
 141 
Total Risk Management Liabilities
$
 40 
  
$
 11,803 
  
$
 - 
  
$
 (4,702)
  
$
 7,141 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2011
PSO
                  
   
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in thousands)
                               
Risk Management Assets
                            
Risk Management Commodity Contracts (a) (f)
$
 97 
  
$
 7,797 
  
$
 - 
  
$
 (7,015)
  
$
 879 
                               
Liabilities:
                            
                               
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (f)
$
 53 
  
$
 9,542 
  
$
 - 
  
$
 (7,092)
  
$
 2,503 
Cash Flow Hedges:
                            
 
Commodity Hedges
  
 - 
    
 107 
    
 - 
    
 - 
    
 107 
Total Risk Management Liabilities
$
 53 
  
$
 9,649 
  
$
 - 
  
$
 (7,092)
  
$
 2,610 

 
192
 

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2012
SWEPCo
                  
   
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in thousands)
                               
Cash and Cash Equivalents (c)
$
 13,515 
  
$
 - 
  
$
 - 
  
$
 1,102 
  
$
 14,617 
                               
Risk Management Assets
                            
Risk Management Commodity Contracts (a) (f)
  
 93 
    
 14,480 
    
 - 
    
 (12,908)
    
 1,665 
                               
Total Assets
$
 13,608 
  
$
 14,480 
  
$
 - 
  
$
 (11,806)
  
$
 16,282 
                               
Liabilities:
                            
                               
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (f)
$
 50 
  
$
 21,162 
  
$
 - 
  
$
 (13,004)
  
$
 8,208 
Cash Flow Hedges:
                            
 
Commodity Hedges
  
 - 
    
 136 
    
 - 
    
 - 
    
 136 
Total Risk Management Liabilities
$
 50 
  
$
 21,298 
  
$
 - 
  
$
 (13,004)
  
$
 8,344 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2011
SWEPCo
                  
   
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in thousands)
                               
Risk Management Assets
                            
Risk Management Commodity Contracts (a) (f)
$
 122 
  
$
 7,023 
  
$
 - 
  
$
 (6,421)
  
$
 724 
Cash Flow Hedges:
                            
 
Interest Rate/Foreign Currency Hedges
  
 - 
    
 3 
    
 - 
    
 - 
    
 3 
Total Risk Management Assets
$
 122 
  
$
 7,026 
  
$
 - 
  
$
 (6,421)
  
$
 727 
                               
Liabilities:
                            
                               
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (f)
$
 66 
  
$
 11,753 
  
$
 - 
  
$
 (6,479)
  
$
 5,340 
Cash Flow Hedges:
                            
 
Commodity Hedges
  
 - 
    
 97 
    
 - 
    
 - 
    
 97 
 
Interest Rate/Foreign Currency Hedges
  
 - 
    
 19,143 
    
 - 
    
 - 
    
 19,143 
Total Risk Management Liabilities
$
 66 
  
$
 30,993 
  
$
 - 
  
$
 (6,479)
  
$
 24,580 

(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)
Amounts in “Other” column primarily represent cash deposits with third parties.  Level 1 and Level 2 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, I&M and OPCo and coal contracts for PSO and SWEPCo.
 
There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2012 and 2011.
 
193
 
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, 2012
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
   
(in thousands)
Balance as of March 31, 2012
  
$
 7,981 
  
$
 5,614 
  
$
 11,767 
  
$
 - 
  
$
 - 
Realized Gain (Loss) Included in Net Income
                              
 
(or Changes in Net Assets) (a) (b)
    
 (3,210)
    
 (2,258)
    
 (4,734)
    
 - 
    
 - 
Unrealized Gain (Loss) Included in Net
                              
 
Income (or Changes in Net Assets) Relating
                              
 
to Assets Still Held at the Reporting Date (a)
    
 - 
    
 - 
    
 1,711 
    
 - 
    
 - 
Realized and Unrealized Gains (Losses)
                              
 
Included in Other Comprehensive Income
    
 (11)
    
 (8)
    
 (16)
    
 - 
    
 - 
Purchases, Issuances and Settlements (c)
    
 4,988 
    
 3,508 
    
 7,355 
    
 - 
    
 - 
Transfers into Level 3 (d) (f)
    
 1,301 
    
 915 
    
 1,919 
    
 - 
    
 - 
Transfers out of Level 3 (e) (f)
    
 (557)
    
 (392)
    
 (821)
    
 - 
    
 - 
Changes in Fair Value Allocated to Regulated
                              
 
Jurisdictions (g)
    
 2,372 
    
 1,670 
    
 1,788 
    
 - 
    
 - 
Balance as of June 30, 2012
  
$
 12,864 
  
$
 9,049 
  
$
 18,969 
  
$
 - 
  
$
 - 

Three Months Ended June 30, 2011
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
   
(in thousands)
Balance as of March 31, 2011
  
$
 5,472 
  
$
 3,209 
  
$
 6,893 
  
$
 - 
  
$
 - 
Realized Gain (Loss) Included in Net Income
                              
 
(or Changes in Net Assets) (a) (b)
    
 (3,219)
    
 (1,910)
    
 (4,096)
    
 - 
    
 - 
Unrealized Gain (Loss) Included in Net
                              
 
Income (or Changes in Net Assets) Relating
                              
 
to Assets Still Held at the Reporting Date (a)
    
 - 
    
 - 
    
 1,149 
    
 - 
    
 - 
Realized and Unrealized Gains (Losses)
                              
 
Included in Other Comprehensive Income
    
 (50)
    
 (30)
    
 (64)
    
 - 
    
 - 
Purchases, Issuances and Settlements (c)
    
 4,814 
    
 2,856 
    
 6,126 
    
 - 
    
 - 
Transfers into Level 3 (d) (f)
    
 1,125 
    
 661 
    
 1,417 
    
 - 
    
 - 
Transfers out of Level 3 (e) (f)
    
 (213)
    
 (125)
    
 (269)
    
 - 
    
 - 
Changes in Fair Value Allocated to Regulated
                              
 
Jurisdictions (g)
    
 (2,608)
    
 (1,511)
    
 (4,397)
    
 - 
    
 - 
Balance as of June 30, 2011
  
$
 5,321 
  
$
 3,150 
  
$
 6,759 
  
$
 - 
  
$
 - 

 
194
 
Six Months Ended June 30, 2012
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
   
(in thousands)
Balance as of December 31, 2011
  
$
 1,971 
  
$
 1,263 
  
$
 2,666 
  
$
 - 
  
$
 - 
Realized Gain (Loss) Included in Net Income
                              
 
(or Changes in Net Assets) (a) (b)
    
 (5,313)
    
 (3,590)
    
 (7,533)
    
 - 
    
 - 
Unrealized Gain (Loss) Included in Net
                              
 
Income (or Changes in Net Assets) Relating
                              
 
to Assets Still Held at the Reporting Date (a)
    
 - 
    
 - 
    
 7,035 
    
 - 
    
 - 
Realized and Unrealized Gains (Losses)
                              
 
Included in Other Comprehensive Income
    
 52 
    
 34 
    
 71 
    
 - 
    
 - 
Purchases, Issuances and Settlements (c)
    
 11,499 
    
 7,811 
    
 16,397 
    
 - 
    
 - 
Transfers into Level 3 (d) (f)
    
 3,562 
    
 2,341 
    
 4,934 
    
 - 
    
 - 
Transfers out of Level 3 (e) (f)
    
 (4,676)
    
 (3,028)
    
 (6,388)
    
 - 
    
 - 
Changes in Fair Value Allocated to Regulated
                              
 
Jurisdictions (g)
    
 5,769 
    
 4,218 
    
 1,787 
    
 - 
    
 - 
Balance as of June 30, 2012
  
$
 12,864 
  
$
 9,049 
  
$
 18,969 
  
$
 - 
  
$
 - 

Six Months Ended June 30, 2011
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
   
(in thousands)
Balance as of December 31, 2010
  
$
 5,131 
  
$
 3,108 
  
$
 6,583 
  
$
 1 
  
$
 2 
Realized Gain (Loss) Included in Net Income
                              
 
(or Changes in Net Assets) (a) (b)
    
 (2,489)
    
 (1,473)
    
 (3,158)
    
 - 
    
 - 
Unrealized Gain (Loss) Included in Net
                              
 
Income (or Changes in Net Assets) Relating
                              
 
to Assets Still Held at the Reporting Date (a)
    
 - 
    
 - 
    
 4,949 
    
 - 
    
 - 
Realized and Unrealized Gains (Losses)
                              
 
Included in Other Comprehensive Income
    
 (50)
    
 (30)
    
 (64)
    
 - 
    
 - 
Purchases, Issuances and Settlements (c)
    
 3,881 
    
 2,311 
    
 4,955 
    
 - 
    
 - 
Transfers into Level 3 (d) (f)
    
 1,221 
    
 718 
    
 1,539 
    
 - 
    
 - 
Transfers out of Level 3 (e) (f)
    
 (2,853)
    
 (1,713)
    
 (3,648)
    
 - 
    
 - 
Changes in Fair Value Allocated to Regulated
                              
 
Jurisdictions (g)
    
 480 
    
 229 
    
 (4,397)
    
 (1)
    
 (2)
Balance as of June 30, 2011
  
$
 5,321 
  
$
 3,150 
  
$
 6,759 
  
$
 - 
  
$
 - 

(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.

 
195
 
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of June 30, 2012:

APCo
  
Fair Value
  
Valuation
  
Significant
  
Forward Price Range
 
Assets
  
Liabilities
Technique
Unobservable Input (a)
  
Low
  
High
   
(in thousands)
                    
Energy Contracts
  
$
 24,551 
  
$
 12,881 
  
Discounted Cash Flow
  
Forward Market Price
  
$
 10.76 
  
$
 161.12 
FTRs
    
 3,123 
    
 1,929 
  
Discounted Cash Flow
  
Forward Market Price
    
 (4.02)
    
 10.78 
Total
  
$
 27,674 
  
$
 14,810 
                    

I&M
  
Fair Value
  
Valuation
  
Significant
  
Forward Price Range
 
Assets
  
Liabilities
Technique
Unobservable Input (a)
  
Low
  
High
   
(in thousands)
                    
Energy Contracts
  
$
 17,269 
  
$
 9,060 
  
Discounted Cash Flow
  
Forward Market Price
  
$
 10.76 
  
$
 161.12 
FTRs
    
 2,197 
    
 1,357 
  
Discounted Cash Flow
  
Forward Market Price
    
 (4.02)
    
 10.78 
Total
  
$
 19,466 
  
$
 10,417 
                    

OPCo
  
Fair Value
  
Valuation
  
Significant
  
Forward Price Range
 
Assets
  
Liabilities
Technique
Unobservable Input (a)
  
Low
  
High
   
(in thousands)
                    
Energy Contracts
  
$
 36,203 
  
$
 18,995 
  
Discounted Cash Flow
  
Forward Market Price
  
$
 10.76 
  
$
 161.12 
FTRs
    
 4,606 
    
 2,845 
  
Discounted Cash Flow
  
Forward Market Price
    
 (4.02)
    
 10.78 
Total
  
$
 40,809 
  
$
 21,840 
                    

(a)
Represents market prices beyond defined terms for Levels 1 and 2.

8.  INCOME TAXES

AEP System Tax Allocation Agreement

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.

Federal and State Income Tax Audit Status

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2009.  The Registrant Subsidiaries completed the examination of the years 2007 and 2008 in April 2011 and settled all outstanding issues on appeal for the years 2001 through 2006 in October 2011.  The settlements did not have a material impact on the Registrant Subsidiaries’ net income, cash flows or financial condition.  The IRS examination of years 2009 and 2010 started in October 2011.  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 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.  In March 2012, AEP settled all outstanding franchise tax issues with the State of Ohio for the years 2000 through 2009.  The settlements did not have a material impact on the Registrants Subsidiaries' net income, cash flows or financial condition.
 
196
 
Uncertain Tax Positions

The reconciliation of the beginning and ending amount of unrecognized tax benefits for OPCo as a result of the franchise tax settlement with the State of Ohio is as follows:

   
OPCo
   
(in thousands)
Balance at December 31, 2011
  
$
 43,565 
Increase - Tax Positions Taken During a Prior Period
    
 - 
Decrease - Tax Positions Taken During a Prior Period
    
 (23,813)
Increase - Tax Positions Taken During the Current Year
    
 - 
Decrease - Tax Positions Taken During the Current Year
    
 - 
Decrease - Settlements with Taxing Authorities
    
 (4,742)
Decrease - Lapse of the Applicable Statute of Limitations
    
 - 
Balance at June 30, 2012
  
$
 15,010 

9.  FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first six months of 2012 are shown in the tables below:

       
Principal
  
Interest
    
Company
  
Type of Debt
  
Amount
  
Rate
  
Due Date
Issuances:
      
(in thousands)
  
(%)
    
I&M
  
Notes Payable
  
$
 109,500 
  
Variable
  
2016 
I&M
  
Other Long-term Debt
    
 20,000 
(a)
Variable
  
2015 
PSO
  
Notes Payable
    
 2,395 
  
3.00 
  
2027 
SWEPCo
  
Senior Unsecured Notes
    
 275,000 
  
3.55 
  
2022 
SWEPCo
  
Notes Payable
    
 65,000 
  
4.58 
  
2032 
                   
(a) Consists of a $110 million three-year credit facility to be used for general corporate purposes.

         
Principal
  
Interest
    
Company
  
Type of Debt
  
Amount Paid
  
Rate
  
Due Date
Retirements and
      
(in thousands)
  
(%)
    
 
Principal Payments:
                  
APCo
  
Pollution Control Bonds
  
$
 30,000 
  
6.05 
  
2024 
APCo
  
Pollution Control Bonds
    
 19,500 
  
5.00 
  
2021 
APCo
  
Land Note
    
 12 
  
13.718 
  
2026 
I&M
  
Notes Payable
    
 13,860 
  
5.44 
  
2013 
I&M
  
Notes Payable
    
 10,590 
  
4.00 
  
2014 
I&M
  
Notes Payable
    
 11,038 
  
Variable
  
2015 
I&M
  
Notes Payable
    
 11,971 
  
Variable
  
2016 
I&M
  
Notes Payable
    
 8,291 
  
2.12 
  
2016 
I&M
  
Other Long-term Debt
    
 245 
  
6.00 
  
2025 
OPCo
  
Pollution Control Bonds
    
 44,500 
  
4.85 
  
2012 
OPCo
  
Senior Unsecured Notes
    
 150,000 
  
Variable
  
2012 
PSO
  
Notes Payable
    
 32 
  
3.00 
  
2027 
SWEPCo
  
Notes Payable
    
 20,000 
  
7.03 
  
2012 

In July 2012, I&M retired $9 million of Notes Payable related to DCC Fuel.

As of June 30, 2012, trustees held, on behalf of OPCo, $463 million of its reacquired Pollution Control Bonds.
 
197
 
Dividend Restrictions

The Registrant Subsidiaries pay dividends to Parent provided funds are legally available.  Various financing arrangements 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 value of the common stock.

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.

Leverage Restrictions

Pursuant to the credit agreement leverage restrictions, APCo, I&M and OPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.

Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of the subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds AEP’s 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, 2012 and December 31, 2011 is included in Advances to/from Affiliates on each of the Registrant Subsidiaries’ condensed balance sheets.  The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the six months ended June 30, 2012 are described in the following table:

                           
Net
      
                           
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, 2012
  
Limit
   
(in thousands)
APCo
  
$
 275,241 
  
$
 22,979 
  
$
 193,156 
  
$
 22,570 
  
$
 (144,415)
  
$
 600,000 
I&M
    
 - 
    
 246,882 
    
 - 
    
 163,557 
    
 238,466 
    
 500,000 
OPCo
    
 126,975 
    
 290,356 
    
 50,680 
    
 97,642 
    
 32,671 
    
 600,000 
PSO
    
 - 
    
 120,424 
    
 - 
    
 66,085 
    
 120,424 
    
 300,000 
SWEPCo
    
 227,087 
    
 97,022 
    
 147,338 
    
 46,496 
    
 97,022 
    
 350,000 

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,
   
2012 
  
2011 
Maximum Interest Rate
  
 0.56 
%
  
 0.56 
%
Minimum Interest Rate
  
 0.45 
%
  
 0.06 
%

 
198
 
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the six months ended June 30, 2012 and 2011 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
  
2012 
  
2011 
2012 
  
2011 
APCo
  
 0.49 
%
  
 0.38 
%
  
 0.49 
%
  
 0.27 
%
I&M
  
 - 
%
  
 0.44 
%
  
 0.49 
%
  
 0.23 
%
OPCo
  
 0.47 
%
  
 0.45 
%
  
 0.51 
%
  
 0.25 
%
PSO
  
 - 
%
  
 0.41 
%
  
 0.48 
%
  
 0.19 
%
SWEPCo
  
 0.53 
%
  
 0.25 
%
  
 0.48 
%
  
 0.33 
%

Short-term Debt
                        
 
The Registrant Subsidiaries’ outstanding short-term debt was as follows:
 
         
June 30, 2012
  
December 31, 2011
         
Outstanding
  
Interest
  
Outstanding
  
Interest
Company
  
Type of Debt
Amount
Rate (a)
  
Amount
Rate (a)
         
(in thousands)
        
(in thousands)
      
SWEPCo
  
Line of Credit – Sabine
  
$
 - 
  
 - 
%
  
$
 17,016 
  
 1.79 
%

(a)  Weighted average weight.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 3.

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’ condensed income statements.  The Registrant Subsidiaries manage and service their customer accounts receivable sold.

In June 2012, AEP Credit renewed its receivables securitization agreement.  The agreement provides commitments of $700 million from bank conduits to finance receivables from AEP Credit.  A commitment of $385 million expires in June 2013 and the remaining commitment of $315 million expires in June 2015.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of June 30, 2012 and December 31, 2011 was as follows:

     
June 30,
  
December 31,
Company
  
2012 
  
2011 
     
(in thousands)
APCo
  
$
 125,942 
  
$
 121,605 
I&M
    
 126,865 
    
 121,597 
OPCo
    
 319,996 
    
 346,695 
PSO
    
 122,215 
    
 123,172 
SWEPCo
    
 158,924 
    
 140,440 

 
199
 
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
  
2012 
  
2011 
  
2012 
  
2011 
     
(in thousands)
APCo
  
$
 1,556 
  
$
 2,239 
  
$
 3,686 
  
$
 4,814 
I&M
    
 1,521 
    
 1,508 
    
 3,064 
    
 3,135 
OPCo
    
 4,622 
    
 4,405 
    
 10,538 
    
 8,440 
PSO
    
 1,825 
    
 1,483 
    
 3,557 
    
 2,717 
SWEPCo
    
 1,548 
    
 1,303 
    
 2,934 
    
 2,403 

The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:

     
Three Months Ended June 30,
  
Six Months Ended June 30,
Company
  
2012 
  
2011 
  
2012 
  
2011 
     
(in thousands)
APCo
  
$
 295,879 
  
$
 284,715 
  
$
 642,405 
  
$
 650,924 
I&M
    
 320,415 
    
 315,551 
    
 659,996 
    
 666,572 
OPCo
    
 656,737 
    
 831,835 
    
 1,494,634 
    
 1,742,873 
PSO
    
 303,729 
    
 317,060 
    
 576,524 
    
 585,629 
SWEPCo
    
 379,114 
    
 375,903 
    
 700,722 
    
 690,027 

10.  SUSTAINABLE COST REDUCTIONS

In April 2012, management initiated a process to identify employee repositioning opportunities and efficiencies that will result in sustainable cost savings.  The process will result in involuntary severances and is expected to be completed by the end of 2012.  The severance program provides two weeks of base pay for every year of service along with other severance benefits.

The Registrant Subsidiaries recorded a charge to expense in the second quarter of 2012 related to the sustainable cost reductions initiative.

     
Expense
  
Incurred for
        
Remaining
     
Allocation from
  
Registrant
        
Balance at
   
AEPSC
  
Subsidiaries
  
Settled
  
  June 30, 2012
   
(in thousands)
APCo
  
$
 2,010 
  
$
 730 
  
$
 (2,035)
  
$
 705 
I&M
    
 1,204 
    
 71 
    
 (1,088)
    
 187 
OPCo
    
 3,005 
    
 442 
    
 (3,260)
    
 187 
PSO
    
 1,080 
    
 3 
    
 (1,083)
    
 - 
SWEPCo
    
 1,324 
    
 533 
    
 (1,432)
    
 425 

These expenses relate primarily to severance benefits.  They are included primarily in Other Operation on the income statement and Other Current Liabilities on the balance sheet.  At this time, management is unable to estimate the total amount to be incurred in future periods related to this initiative or to quantify the effects on future earnings, cash flows and financial condition.

 
200
 
COMBINED MANAGEMENT’S NARRATIVE 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 Narrative Discussion and Analysis of Results of Operations, (b) financial statements, (c) footnotes and (d) the schedules of each individual registrant.  The Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries section of the 2011 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

Sustainable Cost Reductions

In April 2012, management initiated a process to identify employee repositioning opportunities and efficiencies that will result in sustainable cost savings.  A charge to expense of $13 million was recorded in the second quarter of 2012 related to the elimination of approximately 170 positions across the AEP System in the first phase of this process.  In May 2012, management selected one consulting firm to conduct an organizational and process optimization evaluation and a second consulting firm to evaluate current employee benefit programs.  The second phase of this process is expected to be completed by the end of 2012 with additional cost reductions.

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 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.  AEP, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court.  The U.S. House of Representatives passed legislation called the Transparency in Regulatory Analysis of Impacts on the Nation (the TRAIN Act) that would delay implementation of certain Federal EPA rules to facilitate a comprehensive analysis of their impacts.  The Senate is considering similar legislation.  Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

See a complete discussion of these matters in the “Environmental Issues” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2011 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 certain of these expenditures through market prices in deregulated jurisdictions.  If not, the costs of environmental compliance could reduce future net income and cash flows and impact financial condition.
 
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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, 2012, the AEP System had a total generating capacity of 37,035 MWs, of which 23,900 MWs are coal-fired.  Management continues to refine 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 are listed below:

     
2012 to 2020
     
Estimated Environmental Investment
Company
  
Low
  
High
   
(in millions)
APCo
  
$
 415 
  
$
 515 
I&M
    
 1,490 
    
 1,710 
OPCo
    
 1,260 
    
 1,510 
PSO
    
 430 
    
 530 
SWEPCo
    
 1,250 
    
 1,450 

For APCo and OPCo, the projected environmental investments above include the conversion of 470 MWs and 585 MWs, respectively, of coal generation to 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 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 continuing evaluation, management has given notice to the applicable RTOs of the intent to retire the following plants or units of plants before or during 2016:

       
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, Units 1-4
    
 600 
I&M
  
Tanners Creek Plant, Units 1-3
    
 495 
OPCo
  
Conesville Plant, Unit 3
    
 165 
OPCo
  
Kammer Plant
    
 630 
OPCo
  
Muskingum River Plant, Units 1-4
    
 840 
OPCo
  
Picway Plant
    
 100 
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.  OPCo owns 12.5% (54 MWs) of one unit at that station.

Management is monitoring the potential impact that the proposed corporate separation of OPCo’s generation assets and the proposed termination of the Interconnection Agreement could have on the recoverability of OPCo’s generation assets.
 
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In April 2012, management reached an agreement in principle with the Federal EPA, the State of Oklahoma and other parties to retire one coal-fired unit of PSO’s Northeastern Station no later than 2016, install emission controls on the second coal-fired Northeastern unit in 2016 and retire the second unit no later than 2026.  These two coal-fired units have a combined generating capacity of 930 MWs.  The parties are working toward a final settlement agreement.  Management expects this agreement, if approved, to reduce PSO’s environmental investments for 2012 to 2020 by approximately $400 million to the amounts shown in the table above.

Plans for and the timing of conversion of some of the coal units to natural gas, installing emission control equipment on other units and closure of existing units will be impacted by changes in emission requirements and demand for power.  To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows.

Environmental Control Applications

Rockport Plant

I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit one unit at its Rockport Plant with environmental controls estimated to cost $1.4 billion to comply with new requirements.  AEGCo and I&M jointly own Unit 1 and jointly lease Unit 2 of the Rockport Plant.  I&M is also evaluating options related to the maturity of the lease for Rockport Plant Unit 2 in 2022 and continues to investigate alternative compliance technologies for these Units as part of its overall compliance strategy.  As of June 30, 2012, AEGCo and I&M have incurred $10 million and $10 million, respectively, related to this project.

In July 2012, certain intervenors filed testimony which recommended costs caps ranging from $1.1 billion to $1.4 billion if the IURC approved the CPCN.  In addition, the Indiana Office of Utility Consumer Counselor recommended the CPCN be denied until a more detailed and precise project plan and cost estimates are filed with the IURC.  If I&M receives approval of a CPCN, I&M will file for cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism.  An IURC decision is expected in the fourth quarter of 2012.

Flint Creek Plant

In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA.  The estimated cost of the project is $408 million, excluding AFUDC and company overheads.  As a joint owner of the Flint Creek Plant, SWEPCo’s portion of those costs is estimated at $204 million.  Through June 30, 2012, SWEPCo has incurred $9 million related to this project.  In June 2012, the APSC staff and the Arkansas Attorney General’s office filed testimony that recommended additional analysis be performed in order to reach a final conclusion.  The Sierra Club filed testimony that recommended the APSC deny the declaratory order.  SWEPCo is currently reviewing the testimony and will file rebuttal testimony on July 30, 2012.  A decision is pending from the APSC.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions.  The states implement and administer many of these programs and could impose additional or more stringent requirements.

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas.  BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.  CAVR will be implemented through individual state implementation plans (SIPs) or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs).  The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas and Oklahoma.  The Federal EPA finalized a FIP for Oklahoma that contains more stringent control requirements for SO2 emissions from affected units in that state.  No action has been finalized in Arkansas.  In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the Cross-State Air Pollution Rule (CSAPR) trading programs to use those programs in place of source-specific BART
 
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for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states.  As a result, depending on how the states decide to implement the CAVR, compliance with the CSAPR requirements may be sufficient to satisfy CAVR's BART requirements without the need for additional unit-specific controls.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for SO2, NOx and lead, and is currently reviewing the NAAQS for ozone and PM.  States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for facilities as a result of those evaluations.  Management cannot currently predict the nature, stringency or timing of those requirements.

Notable developments in significant CAA regulatory requirements affecting the Registrant Subsidiaries’ operations are discussed in the following sections.

Cross-State Air Pollution Rule (CSAPR)

In August 2011, the Federal EPA issued CSAPR.  Certain revisions to the rule were finalized in March 2012.  CSAPR 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 and Louisiana are subject only to the seasonal NOx program in the rule.  Texas is 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 rule.  Numerous affected entities, states and other parties filed petitions to review the CSAPR in the United States Court of Appeals for the District of Columbia Circuit.  Several of the petitioners filed motions to stay the implementation of the rule pending judicial review.  In December 2011, the court granted the motions for stay.  Oral argument was heard in April 2012.  A supplemental rule includes Oklahoma in the seasonal NOx program.  The supplemental rule was finalized in December 2011, with an increased NOx emission budget for the 2012 compliance year.  A separate appeal of the supplemental rule has been filed, but is being held in abeyance until the court issues a decision in the main CSAPR appeal.  The Federal EPA issued a final Error Corrections Rule and further CSAPR revisions in 2012 to make corrections to state budgets and unit allocations and to remove the restrictions on interstate trading in the first phase of CSAPR.  Challenges to these rules have also been filed, but are being held in abeyance pending a decision in the main appeal.

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.   Management cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In February 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal, 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.  The effective date of the final rule was April 16, 2012 and compliance is required within three years.  The AEP System is participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed.   In July 2012, the Federal EPA issued a letter announcing that it will grant petitions for administrative reconsideration of certain issues related to the new source standards, including measurement issues and application of variability factors that may have an impact on the level of the standards.  The letter also announced a three-month stay in the effective date of the new source standards.  It is uncertain whether any of the information generated during the reconsideration process will affect the standards for existing sources.
 
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The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and allows operators to exclude periods of startup and shutdown from the emissions averaging periods.  The compliance time frame remains a serious concern.  A one-year administrative extension may be available if the extension is necessary for the installation of controls or to avoid a serious reliability problem.  In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades.  Management is concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines.  The AEP System is participating in petitions for review filed in the United States Court of Appeals for the District of Columbia Circuit by several organizations in which the Registrant Subsidiaries are members.  Certain issues related to the standards for new coal-fired units have been severed from the main case and will be considered by the court on an expedited basis.  The Federal EPA’s grant of certain reconsideration petitions may alter this schedule.

Regional Haze – Affecting PSO

In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze SIP submitted by the State of Oklahoma through the Department of Environmental Quality.  The Federal EPA proposed 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 proposed a 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.  PSO submitted comments on the proposed action demonstrating that the cost-effectiveness calculations performed by the Federal EPA were unsound, challenging the period for compliance with the final rule and showing that the visibility improvements secured by the proposed SIP were significant and cost-effective.  The Federal EPA finalized the FIP in December 2011 that mirrored the proposed rule but established a five-year compliance schedule.  PSO filed a petition for review of the FIP in the Tenth Circuit Court of Appeals and engaged in settlement discussions with the Federal EPA, the State of Oklahoma and other parties.  In April 2012, an agreement in principle was reached that would provide for submission of a revised Regional Haze SIP requiring the retirement of one coal-fired unit of PSO’s Northeastern Station no later than 2016, installation of emission controls on the second coal-fired Northeastern unit in 2016 and retirement of the second unit no later than 2026.  The parties are working toward finalizing a settlement agreement which is intended to allow PSO to meet its compliance obligations under the regional haze and HAPs rules.

CO2 Regulation

In March 2012, the Federal EPA issued a proposal to regulate CO2 emissions from new fossil fuel-fired electricity generating units.  The proposed rule establishes a new source performance standard of 1,000 pounds of CO2 per megawatt hour of electricity generated, a rate that most natural gas combined cycle units can meet, but that is substantially below the emission rate of a new pulverized coal generator or an integrated gas combined cycle unit that uses coal for fuel.  As proposed, the rule does not apply to new gas-fired stationary combustion turbines used as peaking units, does not apply to existing, modified or reconstructed sources, and does not apply to units whose CO2 emission rate increases as a result of the addition of pollution control equipment to control criteria or HAPs.  The rule is not anticipated to have a significant immediate impact on the AEP System since it does not apply to existing units or units that have already commenced construction, like SWEPCo’s Turk Plant.  The comment period closed in June 2012.  New Source Performance Standards affect units that have not yet received permits, but complete the permitting process while the proposal is pending.  The standards have been challenged in the United States Court of Appeals for the District of Columbia Circuit.  Management cannot predict the outcome of that litigation.

In June 2012, the United States Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO2 emissions from new motor vehicles and its plan to phase in regulation of CO2 emissions from stationary source under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs.  The Federal EPA also finalized a rule in June 2012 that retains the current thresholds for permitting stationary sources under the PSD and Title V operating permit programs at 100,000 tons per year for new sources and 75,000 tons per year for modified sources.  The Federal EPA also confirmed that it will re-evaluate these thresholds during its five-year review in 2016.  The AEP System’s generating units are large sources of CO2 emissions and management will continue to evaluate the permitting obligations in light of these thresholds.
 
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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 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.  In October 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment.  The Federal EPA has also announced its intention to complete a risk assessment of various beneficial uses of coal ash.

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 under the proposed solid waste management alternative.  Regulation of these materials as hazardous wastes would significantly increase these costs.  As the rule is not final, management is unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

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.  In June 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments.  Management submitted comments in July 2012.  Issuance of a final rule is not expected until July 2013.  Management is preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

Global Warming

National public policy makers and regulators in the 10 states the Registrant Subsidiaries serve have conflicting views on global warming.  While comprehensive economy-wide regulation of CO2 emissions might be achieved through future 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.

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 Michigan, Ohio, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements.  Management is taking steps to comply with these requirements.
 
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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 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 3.

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 reduce future net income and cash flows and impact financial condition.

For additional information on global warming, other environmental issues and the actions management is taking to address potential impacts, see Part I of the 2011 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters” and “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries.”

ACCOUNTING PRONOUNCEMENTS

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 instruments, leases, insurance, hedge accounting and consolidation policy.  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.
 
Item 4.  Controls and Procedures

During the second quarter of 2012, management, including the principal executive officer and principal financial officer of each of AEP, APCo, 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, 2012, 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 2012 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 3 incorporated herein by reference.

Item 1A.  Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2011 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 2011 Annual Report on Form 10-K.

GENERAL RISKS OF OUR REGULATED OPERATIONS

We may not fully recover all of the investment in and expenses related to the Turk Plant – Affecting AEP and SWEPCo

SWEPCo is currently constructing the Turk Plant in Arkansas and holds a 73% ownership interest in the planned 600 MW coal-fired generating facility.  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.  SWEPCo announced that it would continue construction of the Turk Plant and would not currently seek authority to serve Arkansas retail customers.  In June 2010, the APSC reversed and set aside the previously granted CECPN.  SWEPCo currently has no contracts for the 88 MW of Turk Plant output but is evaluating its options.  If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could materially reduce future net income and cash flows and materially impact financial condition.

Rate and other recovery in Ohio for distribution service may not provide full recovery of costs. – Affecting AEP and OPCo

In February 2011, OPCo filed with the PUCO for an annual increase in distribution rates.  In December 2011, a stipulation was approved by the PUCO providing recovery of certain distribution regulatory assets.  Because the February 2012 PUCO order rejected the ESP modified stipulation, collection of the Distribution Investment Rider (DIR) terminated.  In March 2012, OPCo filed an application with the PUCO to approve an ESP for the period June 2012 through May 2015, which includes a request for a new DIR.  If OPCo is not ultimately permitted to fully recover its costs, it would reduce future net income and cash flows and impact financial condition.

Rate recovery in Ohio for generation service may not provide full recovery of costs. – Affecting AEP and OPCo

In March 2012, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing.  The SSO rates would be effective through May 2015.  The ESP will transition OPCo to an auction-based SSO for capacity and energy by June 2015.  If OPCo is not able to recover its costs, it would reduce future net income and cash flows and impact financial condition.
 
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Rate recovery approved in Ohio may have to be returned and/or may not provide full recovery of costs. – Affecting AEP and OPCo

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates through 2011.  The ESP order generally authorized rate increases during the ESP period, subject to caps that limit the rate increases, and also provided a fuel adjustment clause for the three-year period of the ESP.  The recovery under the fuel adjustment clause included 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.  In January 2011, the PUCO issued an order on the 2009 SEET filing, which is currently under appeal at the Supreme Court of Ohio.  In July 2011, OPCo filed its 2010 SEET filing with the PUCO.  OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis.  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 recovered for other reasons, it could reduce future net income and cash flows and impact financial condition.

Ohio may require us to refund additional fuel costs. – Affecting AEP and OPCo

In January 2012, the PUCO ordered that proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance.  Further, the January 2012 PUCO order stated that a consultant be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.  Management is unable to predict the outcome of the consultant’s recommendation.  If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultants’ review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

The PUCO-selected outside consultant issued its results of the 2010 and 2011 FAC audit.  The audit reports included recommendations that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes.  If the PUCO orders result in a reduction to the FAC deferral, it would reduce future net income and cash flows and impact financial condition.

Request for rate recovery in Indiana may not be approved in its entirety. – Affecting AEP and I&M

In September 2011, I&M filed a request with the IURC for annual increases in Indiana base rates.  If the IURC denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

Request for rate recovery in Texas may not be approved in its entirety. – Affecting AEP and SWEPCo

In July 2012, SWEPCo filed a request with the PUCT for an annual increase in Texas base rates.  If the PUCT denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

RISKS RELATING TO STATE RESTRUCTURING

We are unable to fully predict the effects of corporate separation in Ohio and becoming subject to market forces. – Affecting AEP and OPCo

In March 2012, OPCo filed a corporate separation plan with the PUCO for its generation assets.  Additional filings at the FERC and other state commissions related to corporate separation are expected to be filed in the future.  Our results of operations related to generation will be determined by our ability to sell power and capacity at a profit at rates determined by the prevailing market.  If we are unable to sell power and capacity at a profit, it could reduce future net income and cash flows and impact financial condition.  We can give no assurance that the PUCO, the FERC or other state commissions will not impose material adverse terms as a condition to approving our corporate separation.  Additionally, certain of our generation units may no longer be cost effective and may be retired prior to the end of their anticipated useful life.  This could result in material impairments.
 
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We are unable to predict the consequences of terminating the Interconnection Agreement. – Affecting AEP, APCo, I&M and OPCo

The proposed corporate separation plans of OPCo’s generation assets will require us to either terminate or substantially alter the Interconnection Agreement.  The Interconnection Agreement permits AEP East companies to share costs and benefits associated with their generating plants on a cost basis.  It is unknown at this time whether the Interconnection Agreement 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.  If the Interconnection Agreement is terminated without any subsequent agreements between some or all of the parties, surplus members will no longer automatically sell to deficit members, and they may not be able to otherwise sell that surplus in amounts or at rates equal to what they obtained under the Interconnection Agreement.  Conversely, deficit members will no longer automatically purchase from surplus members, and they may not be able to otherwise purchase in amounts or at rates equal to what they obtained under the Interconnection Agreement.  The possible loss of these sales by the surplus members and the potential increase in costs for the deficit members could reduce future net income and cash flows.  We intend to file an application to terminate the Interconnection Agreement with the FERC in the future.  We can give no assurance that the FERC will not impose material adverse terms as a condition to approving these arrangements.

RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Financial derivatives reforms could increase the liquidity needs and costs of our commercial trading operations. – Affecting each Registrant

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was signed into law.  The federal legislation was enacted to reform financial markets and significantly alter how over-the-counter (OTC) derivatives are regulated.  The law increased regulatory oversight of OTC energy derivatives, including: (a) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the Commodity Futures Trading Commission (CFTC), (b) imposing new and potentially higher capital and margin requirements and (c) authorizing the establishment of overall volume and position limits.  Regulations recently issued by CFTC exempt end users of energy commodities from being required to clear OTC derivatives if they are hedge commercial risk and satisfy certain other requirements, which could reduce the effect of the law's clearing requirements on our hedging activity.  The CFTC has also recently issued other rules that further define the OTC derivative products and entities subject to additional regulatory oversight.  These requirements could subject us to additional regulatory oversight related to our OTC derivative transactions, cause our OTC derivative transactions to be more costly and have an adverse effect on our liquidity due to additional capital requirements.  In addition, as these reforms aim to standardize OTC products it could limit the effectiveness of our hedging programs because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to manage.
 
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Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

NONE

Item 4.  Mine Safety Disclosures

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, and OPCo, through its ownership of Conesville Coal Preparation Company (CCPC) and 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 and its related regulations require companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act.  Exhibit 95 contains the notices of violation and proposed assessments received by DHLC, CCPC and Conner Run under the Mine Act for the quarter ended June 30, 2012.

Item 5.  Other Information

NONE

Item 6.  Exhibits

10 – AEP System Senior Officer Incentive Plan Amended and Restated as of February 28, 2012

12 – Computation of Consolidated Ratio of Earnings to Fixed Charges

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

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

95 – Mine Safety Disclosures

101.INS – XBRL Instance Document
101.SCH – XBRL Taxonomy Extension Schema
101.CAL – XBRL Taxonomy Extension Calculation Linkbase
101.DEF – XBRL Taxonomy Extension Definition Linkbase
101.LAB – XBRL Taxonomy Extension Label Linkbase
101.PRE – XBRL Taxonomy Extension Presentation Linkbase

 
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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
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 27, 2012


 
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