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 September 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
October 25, 2012
       
American Electric Power Company, Inc.
   
485,249,096
     
($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
September 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
 
82
 
Condensed Consolidated Financial Statements
 
88
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
94
       
Indiana Michigan Power Company and Subsidiaries:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
96
 
Condensed Consolidated Financial Statements
 
103
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
109
       
Ohio Power Company Consolidated:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
111
 
Condensed Consolidated Financial Statements
 
119
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
125
       
Public Service Company of Oklahoma:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
127
 
Condensed Financial Statements
 
130
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
136
       
Southwestern Electric Power Company Consolidated:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
138
 
Condensed Consolidated Financial Statements
 
143
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
149
       
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
150
       
Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries
 
207
       
Controls and Procedures
 
214
 
 
 

 
         
Part II.  OTHER INFORMATION
   
     
 
Item 1.
Legal Proceedings
 
215
 
Item 1A.
Risk Factors
 
215
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
217
 
Item 4.
Mine Safety Disclosures
 
217
 
Item 5.
Other Information
 
218
 
Item 6.
Exhibits:
 
218
         
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
   
219

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.
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.
FERC
 
Federal Energy Regulatory Commission.
FGD
 
Flue Gas Desulfurization or scrubbers.
 
 
i

 
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.
MWh
 
Megawatthour.
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

 
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, a 543 MW natural gas unit owned by SWEPCo.
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 storms, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
·
Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·
Availability of necessary generating capacity and the performance of our generating plants.
·
Our ability to resolve cost-related issues regarding I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration and outage through warranty, insurance and the regulatory process.
·
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.
·
Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
·
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, coal, natural gas and other energy-related commodities.
·
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.
·
Volatility and changes in markets for electricity, coal, 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.
·
Our ability to successfully manage negotiations with stakeholders and obtain regulatory approval to terminate or amend the Interconnection Agreement.
·
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.
·
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.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
·
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

June 2012 – May 2015 Ohio ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP through May 2015.  The ESP allowed the continuation of the fuel adjustment clause and established a non-bypassable Distribution Investment Rider (DIR) effective September 2012 through May 2015 to recover, with certain caps, post-August 2010 distribution investment.  The DIR is capped at $86 million in 2012, $104 million in 2013, $124 million in 2014 and $52 million for the period January through May 2015, for a total of $366 million.  The ESP also maintained recovery of several previous ESP riders and required OPCo to contribute $2 million per year during the ESP to the Ohio Growth Fund.  In addition, the ESP approved a storm damage recovery mechanism which allowed OPCo to defer the majority of the incremental distribution operation and maintenance costs from 2012 storms.

Finally, the PUCO ordered OPCo to conduct an energy-only auction for 10% of the standard service offer (SSO) load with delivery beginning six months after the receipt of ESP and corporate separation orders and extending through December 2014.  The PUCO also ordered OPCo to conduct an energy-only auction for a total of 60% of the SSO load with delivery beginning June 2014 through May 2015.  In addition, the PUCO ordered OPCo to conduct an energy-only auction for the remaining 40% of the SSO load for delivery from January 2015 through May 2015.  Starting in June 2015, OPCo will conduct energy and capacity auctions for its entire SSO load.  In September 2012, OPCo and intervenors filed applications with the PUCO for rehearing.  Rehearing of this order is pending at the PUCO.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of 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.  Several parties, including OPCo, requested rehearing of the July 2012 PUCO order, which was upheld by the PUCO in October 2012.  In the August 2012 PUCO order which adopted and modified the new ESP, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR is intended to provide $508 million over the ESP period and will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the deferred capacity costs.  In August 2012, the Industrial Energy Users-Ohio (IEU) filed a claim before the Supreme Court of Ohio stating, among other things, that OPCo’s collection of its capacity costs is illegal.  OPCo and the PUCO filed motions to dismiss IEU’s claim.  If OPCo is ultimately not permitted to fully collect its deferred capacity costs and ESP rates, including the RSR, it would reduce future net income and cash flows and impact financial condition.  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 third quarter of 2011 and the first nine months of 2011, we lost approximately $67 million and $165 million, respectively, of gross margin.  This reduction in gross margin is partially offset by (a) collection of capacity revenues from CRES providers, (b) off-system sales, (c) deferral of unrecovered capacity costs, (d) Retail Stability Rider collections from Ohio retail distribution customers and (e) revenues from AEP Energy, our CRES provider and member of our Generation and Marketing segment.  As of September 30, 2012, based upon an average annual load, approximately 42% of our Ohio load had switched to CRES providers and approximately 6% of our Ohio load had formally initiated the switching process to a CRES provider for a total of 48%.  To enhance our competitive position in Ohio, AEP Energy targets retail customers, both within and outside of our retail service territory.

 
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.  In October 2012, the PUCO issued an order which approved the transfer of OPCo’s generation assets at net book value to AEP Generation Resources, Inc. (AEPGenCo), a nonregulated affiliate in the Generation and Marketing segment.  AEPGenCo will also assume the associated generation liabilities.  Management intends to file an application with the FERC in the fourth quarter of 2012 related to corporate separation.  Our results of operations related to generation in Ohio will be largely 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.

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.  Management intends to file an application with the FERC in the fourth quarter of 2012 to terminate the Interconnection Agreement.  It is unknown 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 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.

Based on the interdependent nature of generation activities subject to the Interconnection Agreement, the AEP East companies’ generation assets are evaluated for their accounting recoverability collectively as an asset group.  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 accounting evaluation of the recoverability of the net book values of OPCo’s generation assets.  The net book value of the OPCo units that we plan to retire included in the table below in the “Environmental Controls Impact on the Generating Fleet” section and our share of W. C. Beckjord Generating Station was $284 million as of September 30, 2012.  These generating assets are being depreciated through May 2015.

Significantly Excessive Earnings Test

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off in 2010 and a subsequent refund to customers during 2011.  In May 2011, the Industrial Energy Users-Ohio and the Ohio Energy Group 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 a portion 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 one month after the PUCO issues an order on the 2010 SEET.  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.

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 an increase of approximately $25 million in annual depreciation expense.  Included in the depreciation rates increase was a decrease in the average remaining life of Tanners Creek Plant to account for the change in the retirement date of Tanners Creek Plant, Units 1-3 from 2020 to 2014.  In May 2012, I&M filed rebuttal testimony which changed the retirement date for Tanners Creek Plant, Units 1-3 to 2015.

 
2

 
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 included a return on and of the Texas jurisdictional share of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operations and maintenance costs.  In September 2012, an Administrative Law Judge issued an order that granted the establishment of SWEPCo’s existing rates as temporary rates beginning in late January 2013, subject to true-up to the final PUCT-approved rates.  A decision from the PUCT is expected in the second quarter of 2013.  See “2012 Texas Base Rate Case” section of Note 2.

Special Rate Mechanism for Ormet

In October 2012, the PUCO issued an order approving a delayed payment plan for Ormet of its October and November 2012 power billings in equal monthly installment payments over the period January 2014 to May 2015 without interest.  In the event Ormet, a large industrial customer in Ohio, does not pay the deferred billings, the PUCO permitted OPCo to recover the unpaid balance up to $20 million in future rates.  To the extent unpaid deferred billings exceed $20 million, it will reduce future net income and cash flows.

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.  As a result, the NRC issued orders and guidance that increase procedures and testing requirements, require physical modifications to the plant and will increase future operating costs at the Cook Plant.  We anticipate that future cumulative compliance costs will range from $40 million to $50 million.  Approximately half of this estimate is expected to be capital.  The remainder will be operating expenses that generally is expected to be incurred over the plant’s life.

 
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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 increasing oversight of nuclear generating facilities.  We are unable to predict the impact of potential future regulation of nuclear facilities.

Cook Plant 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.  A hearing at the IURC is scheduled for January 2013.  In Michigan, I&M requested that the MPSC approve a Certificate of Need and authorize I&M to defer, on an interim basis, incremental depreciation and related property tax costs, including interest, along with study, analysis and development costs until the applicable LCM costs are included in I&M’s base rates.  As of September 30, 2012, I&M has incurred $109 million related to the LCM Project, including AFUDC.  Several intervenors filed testimony with various recommendations.  If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.  See “Cook Plant Life Cycle Management Project” section of Note 2.

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.

 
4

 
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 September 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.  If natural gas conversion is not completed, the units could be closed sooner than planned.

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.

In September 2012, based upon an agreement in principle with the Federal EPA, the State of Oklahoma and other parties, PSO filed an environmental compliance plan with the OCC to retire Units 3 and 4 of the Northeastern Station, a total of 930 MWs, in 2026 and 2016, respectively.  See “Oklahoma Environmental Compliance Plan” and “Regional Haze” sections below.

Natural gas prices and pending environmental rules could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of certain coal-fired units.  We are still evaluating our 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 based on 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 under our accounting evaluations, it could materially reduce future net income and cash flows.

 
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Environmental Compliance Applications

Rockport Plant Environmental Controls

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 September 30, 2012, we have incurred $48 million, including AFUDC.  If we are not ultimately permitted to recover our incurred costs, it would reduce future net income and cash flows.

In July 2012, certain intervenors filed testimony which recommended cost 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 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.  A hearing is scheduled for December 2012.

Big Sandy Unit 2 FGD System

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

Flint Creek Plant Environmental Controls

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 September 30, 2012, SWEPCo has incurred $10 million related to this project, including AFUDC.  The APSC staff and the Sierra Club filed testimony that recommended the APSC deny the requested declaratory order.  A hearing at the APSC was held in October 2012 and a decision is pending from the APSC.  If SWEPCo is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC which requested approval for (a) full cost recovery through base rates by 2026 of an estimated $256 million of new environmental investment that will be incurred prior to 2016 at Northeastern Station Unit 3, (b) full cost recovery through 2026 of Northeastern Station Units 3 and 4 net book value (combined net book value of the two units is $235 million as of September 30, 2012), (c) full cost recovery through base rates of an estimated $83 million of new investment incurred through 2016 at various gas units and (d) a new 15-year purchase power agreement with Calpine Oneta Power, effective in 2016, with cost recovery through a rider, including an earnings component of $3 million.  Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery when filing its next base rate case, which is expected to occur no later than 2014.

 
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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 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.  The Arkansas SIP was disapproved and the state is developing a revised submittal.  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.  This rule is being challenged in the United States Court of Appeals for the District of Columbia Circuit and its fate is uncertain given recent developments in the CSAPR litigation.

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.

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.  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 were reduced significantly in the final rule.  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.  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.

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.  In August 2012, the panel issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the Clean Air Interstate Rule until a replacement rule is finalized.  The majority determined that the CAA does not allow the Federal EPA to “overcontrol” emissions in an upwind state and that the Federal EPA exceeded its statutory authority by failing to allow states an opportunity to develop their own implementation plans before issuing a FIP.  The Federal EPA and other respondents have filed petitions for rehearing.  Separate appeals of the supplemental rule, the Error Corrections Rule and the further revisions have been filed, but are being held in abeyance until the court responds to the rehearing petition in the main CSAPR 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.

 
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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.  The Federal EPA granted petitions to reconsider certain issues related to the new source standards.  Action by the court on these severed issues is being held in abeyance pending action on those petitions.  The case is proceeding on the remaining issues and briefing is scheduled to be completed by April 2013.

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.

 
8

 
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 sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. A petition for rehearing was filed and the court ordered the Federal EPA to respond in October 2012.   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.

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.

 
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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.

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.”

 
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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 and 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 Income Before Extraordinary Item by segment for the three and nine months ended September 30, 2012 and 2011.  We reclassified prior year amounts to conform to the current year’s presentation.

   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2012
   
2011
   
2012
   
2011
 
   
(in millions)
 
Utility Operations
  $ 471     $ 633     $ 1,220     $ 1,357  
Transmission Operations
    14       9       31       19  
AEP River Operations
    (1 )     17       11       23  
Generation and Marketing
    10       8       4       20  
All Other (a)
    (6 )     (10 )     (25 )     (54 )
Income Before Extraordinary Item
  $ 488     $ 657     $ 1,241     $ 1,365  

(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

Third Quarter of 2012 Compared to Third Quarter of 2011

Income Before Extraordinary Item decreased from $657 million in 2011 to $488 million in 2012 primarily due to:

·
A decrease in carrying costs income due to the recognition in the third quarter 2011 of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005.
·
The loss of retail customers in Ohio to various CRES providers.
·
A decrease in weather-related usage.
·
A decrease in AEP River Operations' earnings due to the impact of the 2012 drought.

These decreases were partially offset by:

·
The third quarter 2011 plant impairments of Sporn Unit 5 and the FGD project at Muskingum River Unit 5.

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

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Income Before Extraordinary Item decreased from $1,365 million in 2011 to $1,241 million in 2012 primarily due to:

·
A decrease in carrying costs income due to the recognition in the third quarter 2011 of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005.
·
The loss of retail customers in Ohio to various CRES providers.
·
A decrease in weather-related usage.
·
The increase in depreciation expenses as a result of shortened depreciable lives for certain OPCo generating plants.

These decreases were partially offset by:

·
The third quarter 2011 plant impairments of Sporn Unit 5 and the FGD project at Muskingum River Unit 5.
·
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 second quarter 2012 partial reversal of a 2011 deferred fuel adjustment based on an April 2012 PUCO order related to the 2009 FAC audit.
·
A first quarter 2011 settlement of litigation with BOA and Enron.

Average basic shares outstanding increased from 482 million in 2011 to 484 million in 2012.  Actual shares outstanding were 485 million as of September 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
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2012
   
2011
   
2012
   
2011
 
   
(in millions)
 
Revenues
  $ 3,839     $ 4,074     $ 10,482     $ 10,986  
Fuel and Purchased Electricity
    1,401       1,609       3,766       4,136  
Gross Margin
    2,438       2,465       6,716       6,850  
Other Operation and Maintenance
    858       884       2,383       2,586  
Asset Impairments and Other Related Charges
    13       90       13       90  
Depreciation and Amortization
    458       435       1,318       1,226  
Taxes Other Than Income Taxes
    219       210       632       618  
Operating Income
    890       846       2,370       2,330  
Interest and Investment Income
    2       17       5       21  
Carrying Costs Income
    11       291       42       323  
Allowance for Equity Funds Used During Construction
    19       23       59       65  
Interest Expense
    (221 )     (222 )     (662 )     (681 )
Income Before Income Tax Expense and Equity
                               
Earnings
    701       955       1,814       2,058  
Income Tax Expense
    231       324       596       704  
Equity Earnings of Unconsolidated Subsidiaries
    1       2       2       3  
Income Before Extraordinary Item
  $ 471     $ 633     $ 1,220     $ 1,357  

Summary of KWh Energy Sales for Utility Operations
                         
   
Three Months Ended
 
Nine Months Ended
   
September 30,
 
September 30,
 
2012 
 
2011 
 
2012 
 
2011 
   
(in millions of KWhs)
Retail:
                     
 
Residential
 
 17,664 
   
 18,238 
   
 45,617 
   
 48,690 
 
Commercial
 
 14,091 
   
 14,274 
   
 38,444 
   
 38,833 
 
Industrial
 
 14,729 
   
 15,206 
   
 44,798 
   
 44,688 
 
Miscellaneous
 
 824 
   
 854 
   
 2,325 
   
 2,354 
Total Retail (a)
 
 47,308 
   
 48,572 
   
 131,184 
   
 134,565 
                       
Wholesale
 
 12,876 
   
 13,164 
   
 30,409 
   
 32,532 
                       
Total KWhs
 
 60,184 
   
 61,736 
   
 161,593 
   
 167,097 
                         
(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
 
Nine Months Ended
   
September 30,
September 30,
   
2012 
 
2011 
 
2012 
 
2011 
   
(in degree days)
Eastern Region
                     
Actual - Heating (a)
 
 9 
   
 6 
   
 1,388 
   
 1,995 
Normal - Heating (b)
 
 7 
   
 7 
   
 1,923 
   
 1,914 
                         
Actual - Cooling (c)
 
 816 
   
 838 
   
 1,245 
   
 1,209 
Normal - Cooling (b)
 
 709 
   
 700 
   
 1,012 
   
 999 
                         
Western Region
                     
Actual - Heating (a)
 
 - 
   
 - 
   
 348 
   
 702 
Normal - Heating (b)
 
 1 
   
 1 
   
 602 
   
 601 
                         
Actual - Cooling (d)
 
 1,525 
   
 1,669 
   
 2,619 
   
 2,813 
Normal - Cooling (b)
 
 1,367 
   
 1,359 
   
 2,201 
   
 2,179 
                         
(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

 
 
 
Third Quarter of 2012 Compared to Third Quarter of 2011
 
Reconciliation of Third Quarter of 2011 to Third Quarter of 2012
 
Income from Utility Operations before Extraordinary Item
 
(in millions)
 
       
Third Quarter of 2011
  $ 633  
         
Changes in Gross Margin:
       
Retail Margins
    (38 )
Off-system Sales
    (20 )
Transmission Revenues
    20  
Other Revenues
    11  
Total Change in Gross Margin
    (27 )
         
Changes in Expenses and Other:
       
Other Operation and Maintenance
    26  
Asset Impairments and Other Related Charges
    77  
Depreciation and Amortization
    (23 )
Taxes Other Than Income Taxes
    (9 )
Interest and Investment Income
    (15 )
Carrying Costs Income
    (280 )
Allowance for Equity Funds Used During Construction
    (4 )
Interest Expense
    1  
Equity Earnings of Unconsolidated Subsidiaries
    (1 )
Total Change in Expenses and Other
    (228 )
         
Income Tax Expense
    93  
         
Third Quarter of 2012
  $ 471  

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 $38 million primarily due to the following:
 
·
An $80 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 $29 million decrease in weather-related usage primarily due to a 3% and 9% decrease in cooling degree days in our eastern and western service territories, respectively.
 
·
A $10 million net decrease in regulated revenue due to the elimination of POLR charges, effective June 2011, partially offset by the third quarter 2011 provision for refund of POLR charges.  The refund provision was recorded as a result of the October 2011 PUCO remand order.
 
These decreases were partially offset by:
 
·
Successful rate proceedings in our service territories which include:
   
·
A $44 million rate increase for OPCo.
   
·
A $24 million rate increase for APCo.
       
For the rate increases described above, $36 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
   
·
A $13 million decrease in recoverable PJM expenses in Ohio.
·
Margins from Off-system Sales decreased $20 million primarily due to lower market prices, reduced physical sales volumes and lower trading and marketing margins.
·
Transmission Revenues increased $20 million primarily due to net increases in ERCOT and increased transmission revenues from Ohio customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers offsets a portion of the lost revenues included in Retail Margins above.
 
 
15

 
·
Other Revenues increased $11 million primarily due to an 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.

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

·
Other Operation and Maintenance expenses decreased $26 million primarily due to the following:
 
·
A $40 million decrease in plant outage and other plant operating and maintenance expenses.
 
·
A $9 million decrease due to the third quarter 2011 write-off of Ohio allocated Front-End Engineering and Design (FEED) study costs related to the Mountaineer Carbon Capture Project.
 
·
A $4 million decrease in employee-related expenses.
 
These decreases were partially offset by:
 
·
A $16 million increase in energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
 
·
A $12 million increase in storm expenses primarily due to the 2012 summer storms.
·
Asset Impairments and Other Related Charges decreased $77 million primarily due to the third quarter 2011 plant impairments of Sporn Unit 5 and the FGD project at Muskingum River Unit 5.
·
Depreciation and Amortization expenses increased $23 million primarily due to the following:
 
·
A $20 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 $17 million increase due to shortened depreciable lives for certain OPCo generating plants effective December 2011.
 
·
A $15 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.  The majority of this increase in depreciation is offset within Gross Margin.
 
·
A $4 million increase in amortization as a result of the Virginia E&R surcharge and the Virginia Environmental Rate Adjustment Clause, both effective February 2012.  This increase in amortization is offset within Gross Margin.
 
·
A $4 million increase in amortization of the Deferred Asset Recovery Rider assets as approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.  This increase in amortization is offset within Gross Margin.
 
·
Overall higher depreciable property balances.
 
These increases were partially offset by:
 
·
A $21 million decrease due to OPCo's amortization of debt and equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances.  The equity amortization was partially offset by amounts recognized in Carrying Costs Income as discussed below.
 
·
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 $9 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of OPCo's capacity rate proceeding.
·
Interest and Investment Income decreased $15 million primarily due to interest income recorded in the third quarter of 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
·
Carrying Costs Income decreased $280 million primarily due to the following:
 
·
A $261 million decrease in carrying costs income due to the recognition in the third quarter 2011 of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005.
 
·
An $11 million decrease primarily due to the recognition of equity carrying costs income on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances.  The equity carrying costs income was offset by amounts in Depreciation and Amortization discussed above.
·
Income Tax Expense decreased $93 million primarily due to a decrease in pre-tax book income.

 
16

 
 
Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Reconciliation of Nine Months Ended September 30, 2011 to Nine Months Ended September 30, 2012
Income from Utility Operations before Extraordinary Item
(in millions)
         
Nine Months Ended September 30, 2011
 
$
 1,357 
 
         
Changes in Gross Margin:
       
Retail Margins
   
 (153)
 
Off-system Sales
   
 (19)
 
Transmission Revenues
   
 55 
 
Other Revenues
   
 (17)
 
Total Change in Gross Margin
   
 (134)
 
         
Changes in Expenses and Other:
       
Other Operation and Maintenance
   
 203 
 
Asset Impairments and Other Related Charges
   
 77 
 
Depreciation and Amortization
   
 (92)
 
Taxes Other Than Income Taxes
   
 (14)
 
Interest and Investment Income
   
 (16)
 
Carrying Costs Income
   
 (281)
 
Allowance for Equity Funds Used During Construction
   
 (6)
 
Interest Expense
   
 19 
 
Equity Earnings of Unconsolidated Subsidiaries
   
 (1)
 
Total Change in Expenses and Other
   
 (111)
 
         
Income Tax Expense
   
 108 
 
         
Nine Months Ended September 30, 2012
 
$
 1,220 
 

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 $153 million primarily due to the following:
 
·
A $204 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 $119 million decrease in weather-related usage in our eastern and western regions primarily due to decreases of 30% and 50%, respectively, in heating degree days and a 7% decrease in cooling degree days in our western region.
 
·
An $81 million net decrease in regulated revenue due to the elimination of POLR charges, effective June 2011, partially offset by the third quarter 2011 provision for refund of POLR charges.  The refund provision was recorded as a result of the October 2011 PUCO remand order.
 
These decreases were partially offset by:
 
·
Successful rate proceedings in our service territories which include:
   
·
A $94 million rate increase for OPCo.
   
·
A $56 million rate increase for APCo.
   
·
A $16 million rate increase for I&M.
   
·
An $11 million rate increase for PSO.
     
For the rate increases described above, $108 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 $30 million decrease in recoverable PJM expenses in Ohio.
 
 
17

 
 
·
A $9 million deferral of APCo's additional wind purchase recovery costs as a result of the June 2012 Virginia SCC fuel factor order.
·
Margins from Off-system Sales decreased $19 million primarily due to lower market prices, reduced physical sales volumes and lower trading and marketing margins, partially offset by higher PJM capacity revenues.
·
Transmission Revenues increased $55 million primarily due to net increases in ERCOT and increased transmission revenues from Ohio customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers offsets a portion of the lost revenues included in Retail Margins above.
·
Other Revenues decreased $17 million primarily due to a decrease in gains on miscellaneous sales, partially offset by an increase in revenues related to TCC's issuance of securitization bonds in March 2012.  This increase in revenues from securitization bonds is partially offset by an increase in Depreciation and Amortization expense.

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

·
Other Operation and Maintenance expenses decreased $203 million primarily due to the following:
 
·
A $115 million decrease in plant outage and other plant operating and maintenance expenses.
 
·
An $87 million decrease in employee-related expenses.
 
·
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 $30 million net decrease related to the 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 and the PUCO's August 2012 approval of the June 2012-May 2015 ESP.
 
·
A $14 million decrease due to APCo's deferral of transmission costs for the Virginia Transmission Rate Adjustment Clause as allowed by the Virginia SCC.
 
·
A $9 million decrease due to the third quarter 2011 write-off of Ohio allocated FEED study costs related to the Mountaineer Carbon Capture Project.
 
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 $24 million increase in energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
 
·
A $14 million increase due to expenses related to the 2012 sustainable cost reductions.
 
·
An $11 million gain from the sale of land in January 2011.
·
Asset Impairments and Other Related Charges decreased $77 million primarily due to the third quarter 2011 plant impairments of Sporn Unit 5 and the FGD project at Muskingum River Unit 5.
·
Depreciation and Amortization expenses increased $92 million primarily due to the following:
 
·
A $49 million increase due to shortened depreciable lives for certain OPCo generating plants effective December 2011.
 
·
A $42 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 $35 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.  The majority of this increase in depreciation is offset within Gross Margin.
 
·
A $10 million increase in amortization as a result of the Virginia E&R surcharge and the Virginia Environmental Rate Adjustment Clause, both effective February 2012.  This increase in amortization is offset within Gross Margin.
 
·
A $9 million increase in amortization of OPCo's Deferred Asset Recovery Rider assets as approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.  This increase in amortization is offset within Gross Margin.
 
·
Overall higher depreciable property balances.
 
These increases were partially offset by:
 
 
18

 
 
·
A $29 million decrease due to an amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
 
·
A $21 million decrease due to OPCo's amortization of debt and equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances.  The equity amortization was offset by amounts recognized in Carrying Costs Income as discussed below.
 
·
A $13 million decrease in OPCo’s depreciation due to the third quarter 2011 plant impairment of Sporn Unit 5.
 
·
A $9 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of OPCo's capacity rate proceeding.
·
Taxes Other Than Income Taxes increased $14 million primarily due to increased property taxes as a result of increased capital investments.
·
Interest and Investment Income decreased $16 million primarily due to interest income recorded in the third quarter of 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
·
Carrying Costs Income decreased $281 million primarily due to the following:
 
·
A $261 million decrease in carrying costs income due to the recognition in the third quarter 2011 of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005.
 
·
An $11 million decrease due to the recognition of equity carrying costs income on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances.  The equity carrying costs income was offset by amounts in Depreciation and Amortization discussed above.
 
·
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.
 
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.
·
Interest Expense decreased $19 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·
Income Tax Expense decreased $108 million primarily due to a decrease in pre-tax book income and audit settlements for previous years.

TRANSMISSION OPERATIONS

Third Quarter of 2012 Compared to Third Quarter of 2011

Net Income from our Transmission Operations segment increased from $9 million in 2011 to $14 million in 2012 primarily due to an increase in investments by ETT and our wholly-owned transmission subsidiaries.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Net Income from our Transmission Operations segment increased from $19 million in 2011 to $31 million in 2012 primarily due to an increase in investments by ETT and our wholly-owned transmission subsidiaries.

 
19

 
AEP RIVER OPERATIONS

Third Quarter of 2012 Compared to Third Quarter of 2011

Net Income from our AEP River Operations segment decreased from income of $17 million in 2011 to a loss of $1 million in 2012 primarily due to reduced volumes and rates as a result of the 2012 drought which impacted both river conditions and grain harvests.  In addition, as a result of Hurricane Isaac, shipping in the Gulf Region ceased for a period of time in late August and early September 2012.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Net Income from our AEP River Operations segment decreased from $23 million in 2011 to $11 million in 2012 primarily due to reduced volumes and rates as a result of the 2012 drought which impacted both river conditions and grain harvests.  In addition, as a result of Hurricane Isaac, shipping in the Gulf Region ceased for a period of time in late August and early September 2012.

GENERATION AND MARKETING

Third Quarter of 2012 Compared to Third Quarter of 2011

Net Income from our Generation and Marketing segment increased from $8 million in 2011 to $10 million in 2012 primarily due to higher trading margins and higher retail margins in PJM partially offset by lower gross margins at the Oklaunion Plant and the expiration of wind-related production tax credits in 2011.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Net Income from our Generation and Marketing segment decreased from $20 million in 2011 to $4 million in 2012 primarily due to the expiration of wind-related production tax credits in 2011 and lower gross margins at the Oklaunion Plant, partially offset by higher retail margins in PJM and higher trading margins.

ALL OTHER

Third Quarter of 2012 Compared to Third Quarter of 2011

Net Income from All Other increased from a loss of $10 million in 2011 to a loss of $6 million in 2012 primarily due to a reduction in interest expense partially offset by a 2011 gain on sale of assets.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Net Income from All Other increased from a loss of $54 million in 2011 to a loss of $25 million in 2012 primarily due to a loss incurred in the first quarter of 2011 related to the settlement of litigation with BOA and Enron.

AEP SYSTEM INCOME TAXES

Third Quarter of 2012 Compared to Third Quarter of 2011

Income Tax Expense decreased $93 million primarily due to a decrease in pretax book income.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Income Tax Expense decreased $166 million primarily due to a decrease in pretax book income and the 2011 unrealized capital loss valuation allowance related to a deferred tax asset associated with the settlement of litigation with BOA and Enron.

 
20

 
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

   
September 30, 2012
 
December 31, 2011
   
(dollars in millions)
Long-term Debt, including amounts due within one year
$
 17,227 
 
 51.0 
%
 
$
 16,516 
 
 50.3 
%
Short-term Debt
 
 1,216 
 
 3.6 
     
 1,650 
 
 5.0 
 
Total Debt
 
 18,443 
 
 54.6 
     
 18,166 
 
 55.3 
 
AEP Common Equity
 
 15,306 
 
 45.4 
     
 14,664 
 
 44.7 
 
Noncontrolling Interests
 
 - 
 
 - 
     
 1 
 
 - 
 
                       
Total Debt and Equity Capitalization
$
 33,749 
 
 100.0 
%
 
$
 32,831 
 
 100.0 
%

Our ratio of debt-to-total capital decreased from 55.3% as of December 31, 2011 to 54.6% as of September 30, 2012.  Long-term debt outstanding increased primarily 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.  As of September 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.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  As of September 30, 2012, our available liquidity was approximately $3 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
   
 443 
   
Total Liquidity Sources
   
 3,693 
   
Less:
AEP Commercial Paper Outstanding
   
 520 
   
 
Letters of Credit Issued
   
 132 
   
             
Net Available Liquidity
 
$
 3,041 
   

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.

 
21

 
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 nine months of 2012 was $1.2 billion.  The weighted-average interest rate for our commercial paper during 2012 was 0.45%.

Securitized Accounts Receivable

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.  In August 2012, APCo and WPCo filed with the WVPSC a request for a financing order to securitize $422 million related to APCo’s December 2011 under-recovered ENEC deferral balance, other ENEC-related assets and related financing costs.  A hearing is scheduled in December 2012.

In August 2012, OPCo filed an application with the PUCO requesting securitization of the Deferred Asset Recovery Rider (DARR) balance.  As of September 30, 2012, OPCo’s DARR balance was $296 million, including $139 million of unrecognized equity carrying costs.  Currently, the DARR is being recovered through 2018 by a non-bypassable rider.

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.  As of September 30, 2012, this contractually-defined percentage was 49.5%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  As of September 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.  As of September 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 October 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.

 
22

 
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.

CASH FLOW

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

 
Nine Months Ended
 
 
September 30,
 
 
2012
 
2011
 
 
(in millions)
 
Cash and Cash Equivalents at Beginning of Period
$ 221   $ 294  
Net Cash Flows from Operating Activities
  2,912     3,338  
Net Cash Flows Used for Investing Activities
  (2,281 )   (1,967 )
Net Cash Flows Used for Financing Activities
  (409 )   (1,119 )
Net Increase in Cash and Cash Equivalents
  222     252  
Cash and Cash Equivalents at End of Period
$ 443   $ 546  

Cash from operations and short-term borrowings provides working capital and allows us to meet other short-term cash needs.
 
Operating Activities
 
 
Nine Months Ended
 
 
September 30,
 
 
2012
 
2011
 
 
(in millions)
 
Net Income
$ 1,241   $ 1,638  
Depreciation and Amortization
  1,353     1,258  
Other
  318     442  
Net Cash Flows from Operating Activities
$ 2,912   $ 3,338  

Net Cash Flows from Operating Activities were $2.9 billion in 2012 consisting primarily of Net Income of $1.2 billion and $1.4 billion 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 unfavorable impact of an increase in fuel inventory due to the mild winter weather.  Cash was 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.  We also contributed $100 million to our qualified pension trust.

 
23

 
Net Cash Flows from Operating Activities were $3.3 billion in 2011 consisting primarily of Net Income of $1.6 billion and $1.3 billion 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.  Following a Supreme Court of Texas opinion, we recorded an Extraordinary Item, Net of Tax of $273 million for the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005.  We also recorded $261 million in Carrying Costs Income related to the TCC extraordinary item.  A significant change in other items includes the favorable impact of a decrease in fuel inventory.  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.  We also contributed $150 million to our qualified pension trust.
 
Investing Activities
 
 
Nine Months Ended
 
 
September 30,
 
 
2012
 
2011
 
 
(in millions)
 
Construction Expenditures
$ (2,108 ) $ (1,849 )
Acquisitions of Nuclear Fuel
  (13 )   (104 )
Acquisitions of Assets/Businesses
  (89 )   (10 )
Acquisition of Cushion Gas from BOA
  -     (214 )
Proceeds from Sales of Assets
  13     116  
Other
  (84 )   94  
Net Cash Flows Used for Investing Activities
$ (2,281 ) $ (1,967 )

Net Cash Flows Used for Investing Activities were $2.3 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 $2 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
 
 
Nine Months Ended
 
 
September 30,
 
 
2012
 
2011
 
 
(in millions)
 
Issuance of Common Stock, Net
$ 64   $ 70  
Issuance of Debt, Net
  262     (469 )
Dividends Paid on Common Stock
  (687 )   (668 )
Other
  (48 )   (52 )
Net Cash Flows Used for Financing Activities
$ (409 ) $ (1,119 )

Net Cash Flows Used for Financing Activities in 2012 were $409 million.  Our net debt issuances were $262 million. The net issuances included issuances of $800 million of securitization bonds, $550 million of senior unsecured notes, $197 million of notes payable and other debt and $65 million of pollution control bonds offset by retirements of $513 million of senior unsecured and other debt notes, $220 million of pollution control bonds, $171 million of securitization bonds and a decrease in short-term borrowing of $434 million.  We paid common stock dividends of $687 million.  See Note 10 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

 
24

 
Net Cash Flows Used for Financing Activities in 2011 were $1.1 billion.  Our net debt retirements were $469 million. The net retirements included retirements of $683 million of senior unsecured and other debt notes, $678 million of pollution control bonds, $159 million of securitization bonds and a decrease in short-term borrowing of $67 million offset by issuances of $600 million of senior unsecured notes and $526 million of pollution control bonds.  We paid common stock dividends of $668 million.

In October 2012, I&M retired $29 million of Notes Payable related to DCC Fuel.

In October 2012, AEP Transmission Company, LLC completed a $350 million debt offering.  This debt offering resulted in the October 2012 issuance of $250 million of Senior Notes in three tranches.  The tranches are $104 million at 3.3% due in 2022, $85 million at 4% due in 2032 and $61 million at 4.73% due in 2042.  The remaining $100 million will be issued in two tranches in December 2012 and March 2013.

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:

 
September 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.

 
25

 
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.

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)
 
Nine Months Ended September 30, 2012
   
       
Generation
   
   
Utility
and
 
   
Operations
Marketing
Total
   
(in millions)
Total MTM Risk Management Contract Net Assets
               
 
as of December 31, 2011
$
 59 
 
$
 132 
 
$
 191 
(Gain) Loss from Contracts Realized/Settled During the Period and
               
 
Entered in a Prior Period
 
 2 
   
 (2)
   
 - 
Fair Value of New Contracts at Inception When Entered During the
               
 
Period (a)
 
 5 
   
 16 
   
 21 
Acquisition of Supply Contracts (b)
 
 - 
   
 (25)
   
 (25)
Changes in Fair Value Due to Market Fluctuations During the
               
 
Period (c)
 
 4 
   
 2 
   
 6 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
 
 4 
   
 - 
   
 4 
Total MTM Risk Management Contract Net Assets
               
 
as of September 30, 2012
$
 74 
 
$
 123 
   
 197 
                   
Commodity Cash Flow Hedge Contracts
             
 1 
Interest Rate and Foreign Currency Cash Flow Hedge Contracts
             
 (39)
Fair Value Hedge Contracts
             
 2 
Collateral Deposits
             
 30 
Total MTM Derivative Contract Net Assets as of September 30, 2012
           
$
 191 

(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)
Reflects liabilities associated with supply contracts from the BlueStar acquisition in March 2012.
(c)
Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(d)
Relates to the net gains (losses) of those contracts that are not reflected on the condensed 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 September 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 September 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
 
$
 651 
 
$
 - 
 
$
 651 
   
 2 
 
$
 268 
Split Rating
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
Noninvestment Grade
   
 2 
   
 2 
   
 - 
   
 - 
   
 - 
No External Ratings:
                             
 
Internal Investment Grade
   
 109 
   
 - 
   
 109 
   
 2 
   
 27 
 
Internal Noninvestment Grade
   
 60 
   
 10 
   
 50 
   
 1 
   
 36 
Total as of September 30, 2012
 
$
 822 
 
$
 12 
 
$
 810 
   
 5 
 
$
 331 
                                 
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 September 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

Nine Months Ended
 
Twelve Months Ended
September 30, 2012
 
December 31, 2011
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
(in millions)
 
(in millions)
$
 
$
 
$
 
$
 
$
 
$
 
$
 
$

We back-test our VaR results against performance due to actual price movements.  Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

 
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 September 30, 2012 and December 31, 2011, the estimated EaR on our debt portfolio for the following twelve months was $32 million and $29 million, respectively.

 
29

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
For the Three and Nine Months Ended September 30, 2012 and 2011
 
(in millions, except per-share and share amounts)
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
2012
   
2011
   
2012
   
2011
 
REVENUES
                       
Utility Operations
  $ 3,814     $ 4,044     $ 10,412     $ 10,901  
Other Revenues
    342       289       920       771  
TOTAL REVENUES
    4,156       4,333       11,332       11,672  
EXPENSES
                               
Fuel and Other Consumables Used for Electric Generation
    1,180       1,371       3,137       3,407  
Purchased Electricity for Resale
    327       294       855       856  
Other Operation
    775       747       2,150       2,130  
Maintenance
    255       283       769       864  
Asset Impairments and Other Related Charges
    13       90       13       90  
Depreciation and Amortization
    470       445       1,353       1,258  
Taxes Other Than Income Taxes
    224       213       648       628  
TOTAL EXPENSES
    3,244       3,443       8,925       9,233  
                                 
OPERATING INCOME
    912       890       2,407       2,439  
                                 
Other Income (Expense):
                               
Interest and Investment Income
    2       19       6       24  
Carrying Costs Income
    11       291       42       323  
Allowance for Equity Funds Used During Construction
    23       26       70       69  
Interest Expense
    (233 )     (242 )     (697 )     (723 )
                                 
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
    715       984       1,828       2,132  
                                 
Income Tax Expense
    241       334       620       786  
Equity Earnings of Unconsolidated Subsidiaries
    14       7       33       19  
                                 
INCOME BEFORE EXTRAORDINARY ITEM
    488       657       1,241       1,365  
                                 
EXTRAORDINARY ITEM, NET OF TAX
    -       273       -       273  
                                 
NET INCOME
    488       930       1,241       1,638  
                                 
Net Income Attributable to Noncontrolling Interests
    1       1       3       3  
                                 
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS
    487       929       1,238       1,635  
                                 
Preferred Stock Dividend Requirements of Subsidiaries
    -       1       -       2  
                                 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
  $ 487     $ 928     $ 1,238     $ 1,633  
                                 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
    484,979,543       482,498,734       484,437,875       481,862,128  
                                 
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
                               
Income Before Extraordinary Item
  $ 1.00     $ 1.35     $ 2.55     $ 2.82  
Extraordinary Item, Net of Tax
    -       0.57       -       0.57  
                                 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
                               
SHAREHOLDERS
  $ 1.00     $ 1.92     $ 2.55     $ 3.39  
                                 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
    485,362,858       482,796,945       484,826,123       482,126,964  
                                 
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
                               
Income Before Extraordinary Item
  $ 1.00     $ 1.35     $ 2.55     $ 2.82  
Extraordinary Item, Net of Tax
    -       0.57       -       0.57  
                                 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
                               
SHAREHOLDERS
  $ 1.00     $ 1.92     $ 2.55     $ 3.39  
                                 
CASH DIVIDENDS DECLARED PER SHARE
  $ 0.47     $ 0.46     $ 1.41     $ 1.38  
                                 
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 Nine Months Ended September 30, 2012 and 2011
 
(in millions)
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
2012
   
2011
   
2012
   
2011
 
Net Income
  $ 488     $ 930     $ 1,241     $ 1,638  
                                 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                               
Cash Flow Hedges, Net of Tax of $7 and $11 for the Three Months Ended
                               
September 30, 2012 and 2011, Respectively, and $4 and $8 for the Nine
                               
Months Ended September 30, 2012 and 2011, Respectively
    13       (20 )     (8 )     (14 )
Securities Available for Sale, Net of Tax of $- and $2 for the Three Months
                               
Ended September 30, 2012 and 2011, Respectively, and $1 and $2 for the
                               
Nine Months Ended September 30, 2012 and 2011, Respectively
    1       (4 )     2       (3 )
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $4
                               
and $3 for the Three Months Ended September 30, 2012 and 2011,
                               
Respectively, and $12 and $9 for the Nine Months Ended September 30,
                               
2012 and 2011, Respectively
    7       6       22       18  
                                 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
    21       (18 )     16       1  
                                 
TOTAL COMPREHENSIVE INCOME
    509       912       1,257       1,639  
                                 
Total Comprehensive Income Attributable to Noncontrolling Interests
    1       1       3       3  
                                 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
                               
SHAREHOLDERS
    508       911       1,254       1,636  
                                 
Preferred Stock Dividend Requirements of Subsidiaries
    -       1       -       2  
                                 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
                               
COMMON SHAREHOLDERS
  $ 508     $ 910     $ 1,254     $ 1,634  
                                 
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 Nine Months Ended September 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
 
 2 
   
 14 
   
 56 
                     
 70 
Common Stock Dividends
                   
 (665)
         
 (3)
   
 (668)
Preferred Stock Dividend Requirements of
                                       
 
Subsidiaries
                   
 (2)
               
 (2)
Other Changes in Equity
             
 (8)
                     
 (8)
Subtotal – Equity
                                     
 13,014 
                                         
Net Income
                   
 1,635 
         
 3 
   
 1,638 
Other Comprehensive Income
                         
 1 
         
 1 
TOTAL EQUITY – SEPTEMBER 30, 2011
 
 503 
 
$
 3,271 
 
$
 5,952 
 
$
 5,810 
 
$
 (380)
 
$
 - 
 
$
 14,653 
                                         
TOTAL EQUITY – DECEMBER 31, 2011
 
 504 
 
$
 3,274 
 
$
 5,970 
 
$
 5,890 
 
$
 (470)
 
$
 1 
 
$
 14,665 
                                         
Issuance of Common Stock
 
 2 
   
 12 
   
 52 
                     
 64 
Common Stock Dividends
                   
 (684)
         
 (3)
   
 (687)
Other Changes in Equity
             
 8 
               
 (1)
   
 7 
Subtotal – Equity
                                     
 14,049 
                                         
Net Income
                   
 1,238 
         
 3 
   
 1,241 
Other Comprehensive Income
                         
 16 
         
 16 
TOTAL EQUITY – SEPTEMBER 30, 2012
 
 506 
 
$
 3,286 
 
$
 6,030 
 
$
 6,444 
 
$
 (454)
 
$
 - 
 
$
 15,306 
                                         
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
September 30, 2012 and December 31, 2011
(in millions)
(Unaudited)
 
   
2012 
 
2011 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
 443 
 
$
 221 
Other Temporary Investments
           
 
(September 30, 2012 and December 31, 2011 Amounts Include $265 and $281, Respectively, Related to Transition Funding and EIS)
   
 278 
   
 294 
Accounts Receivable:
           
 
Customers
   
 684 
   
 690 
 
Accrued Unbilled Revenues
   
 210 
   
 106 
 
Pledged Accounts Receivable – AEP Credit
   
 909 
   
 920 
 
Miscellaneous
   
 92 
   
 150 
 
Allowance for Uncollectible Accounts
   
 (40)
   
 (32)
   
Total Accounts Receivable
   
 1,855 
   
 1,834 
Fuel
   
 800 
   
 657 
Materials and Supplies
   
 662 
   
 635 
Risk Management Assets
   
 175 
   
 193 
Accrued Tax Benefits
   
 49 
   
 51 
Regulatory Asset for Under-Recovered Fuel Costs
   
 103 
   
 65 
Margin Deposits
   
 74 
   
 67 
Prepayments and Other Current Assets
   
 209 
   
 165 
TOTAL CURRENT ASSETS
   
 4,648 
   
 4,182 
             
PROPERTY, PLANT AND EQUIPMENT
           
Electric:
           
 
Generation
   
 25,463 
   
 24,938 
 
Transmission
   
 9,503 
   
 9,048 
 
Distribution
   
 15,359 
   
 14,783 
Other Property, Plant and Equipment (Including Nuclear Fuel and Coal Mining)
   
 3,943 
   
 3,780 
Construction Work in Progress
   
 3,191 
   
 3,121 
Total Property, Plant and Equipment
   
 57,459 
   
 55,670 
Accumulated Depreciation and Amortization
   
 19,326 
   
 18,699 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
   
 38,133 
   
 36,971 
             
OTHER NONCURRENT ASSETS
           
Regulatory Assets
   
 5,306 
   
 6,026 
Securitized Transition Assets
   
 2,179 
   
 1,627 
Spent Nuclear Fuel and Decommissioning Trusts
   
 1,700 
   
 1,592 
Goodwill
   
 90 
   
 76 
Long-term Risk Management Assets
   
 390 
   
 403 
Deferred Charges and Other Noncurrent Assets
   
 1,397 
   
 1,346 
TOTAL OTHER NONCURRENT ASSETS
   
 11,062 
   
 11,070 
             
TOTAL ASSETS
 
$
 53,843 
 
$
 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
September 30, 2012 and December 31, 2011
(dollars in millions)
(Unaudited)
 
   
2012 
 
2011 
CURRENT LIABILITIES
   
Accounts Payable
 
$
 988 
 
$
 1,095 
Short-term Debt:
           
 
Securitized Debt for Receivable - AEP Credit
     
 696 
   
 666 
 
Other Short-term Debt
     
 520 
   
 984 
   
Total Short-term Debt
     
 1,216 
   
 1,650 
Long-term Debt Due Within One Year
           
 
(September 30, 2012 and December 31, 2011 Amounts Include $375 and $293, Respectively, Related to Transition Funding, DCC Fuel and Sabine)
   
 2,272 
   
 1,433 
Risk Management Liabilities
   
 150 
   
 150 
Customer Deposits
   
 295 
   
 289 
Accrued Taxes
   
 512 
   
 717 
Accrued Interest
   
 249 
   
 279 
Regulatory Liability for Over-Recovered Fuel Costs
   
 76 
   
 8 
Other Current Liabilities
   
 1,037 
   
 990 
TOTAL CURRENT LIABILITIES
   
 6,795 
   
 6,611 
             
NONCURRENT LIABILITIES
           
Long-term Debt
           
 
(September 30, 2012 and December 31, 2011 Amounts Include $2,295 and $1,674, Respectively, Related to Transition Funding, DCC Fuel and Sabine)
   
 14,955 
   
 15,083 
Long-term Risk Management Liabilities
   
 224 
   
 195 
Deferred Income Taxes
   
 8,905 
   
 8,227 
Regulatory Liabilities and Deferred Investment Tax Credits
   
 3,589 
   
 3,195 
Asset Retirement Obligations
   
 1,535 
   
 1,472 
Employee Benefits and Pension Obligations
   
 1,611 
   
 1,801 
Deferred Credits and Other Noncurrent Liabilities
   
 923 
   
 974 
TOTAL NONCURRENT LIABILITIES
   
 31,742 
   
 30,947 
             
TOTAL LIABILITIES
   
 38,537 
   
 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
505,552,303 
 
503,759,460 
             
(20,336,592 Shares were Held in Treasury as of September 30, 2012 and December 31, 2011)
   
 3,286 
   
 3,274 
Paid-in Capital
   
 6,030 
   
 5,970 
Retained Earnings
   
 6,444 
   
 5,890 
Accumulated Other Comprehensive Income (Loss)
   
 (454)
   
 (470)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY
   
 15,306 
   
 14,664 
             
Noncontrolling Interests
   
 - 
   
 1 
             
TOTAL EQUITY
   
 15,306 
   
 14,665 
             
TOTAL LIABILITIES AND EQUITY
 
$
 53,843 
 
$
 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 Nine Months Ended September 30, 2012 and 2011
(in millions)
(Unaudited)
 
   
2012 
 
2011 
OPERATING ACTIVITIES
           
Net Income
 
$
 1,241 
 
$
 1,638 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
           
 
Depreciation and Amortization
   
 1,353 
   
 1,258 
 
Deferred Income Taxes
   
 592 
   
 764 
 
Gain on Settlement with BOA and Enron
   
 - 
   
 (51)
 
Settlement of Litigation with BOA and Enron
   
 - 
   
 (211)
 
Extraordinary Item, Net of Tax
   
 - 
   
 (273)
 
Asset Impairments and Other Related Charges
   
 13 
   
 90 
 
Carrying Costs Income
   
 (42)
   
 (323)
 
Allowance for Equity Funds Used During Construction
   
 (70)
   
 (69)
 
Mark-to-Market of Risk Management Contracts
   
 70 
   
 84 
 
Amortization of Nuclear Fuel
   
 100 
   
 108 
 
Pension Contributions to Qualified Plan Trust
   
 (100)
   
 (150)
 
Property Taxes
   
 181 
   
 173 
 
Fuel Over/Under-Recovery, Net
   
 133 
   
 (94)
 
Change in Other Noncurrent Assets
   
 (195)
   
 (32)
 
Change in Other Noncurrent Liabilities
   
 119 
   
 225 
 
Changes in Certain Components of Working Capital:
           
   
Accounts Receivable, Net
   
 (4)
   
 51 
   
Fuel, Materials and Supplies
   
 (169)
   
 275 
   
Accounts Payable
   
 (135)
   
 (66)
   
Accrued Taxes, Net
   
 (130)
   
 (42)
   
Accrued Interest
   
 (32)
   
 (46)
   
Other Current Assets
   
 (28)
   
 13 
   
Other Current Liabilities
   
 15 
   
 16 
Net Cash Flows from Operating Activities
   
 2,912 
   
 3,338 
             
INVESTING ACTIVITIES
           
Construction Expenditures
   
 (2,108)
   
 (1,849)
Change in Other Temporary Investments, Net
   
 19 
   
 62 
Purchases of Investment Securities
   
 (745)
   
 (1,024)
Sales of Investment Securities
   
 699 
   
 1,094 
Acquisitions of Nuclear Fuel
   
 (13)
   
 (104)
Acquisitions of Assets/Businesses
   
 (89)
   
 (10)
Acquisition of Cushion Gas from BOA
   
 - 
   
 (214)
Proceeds from Sales of Assets
   
 13 
   
 116 
Other Investing Activities
   
 (57)
   
 (38)
Net Cash Flows Used for Investing Activities
   
 (2,281)
   
 (1,967)
             
FINANCING ACTIVITIES
           
Issuance of Common Stock, Net
   
 64 
   
 70 
Issuance of Long-term Debt
   
 1,600 
   
 1,118 
Commercial Paper and Credit Facility Borrowings
   
 21 
   
 462 
Change in Short-term Debt, Net
   
 (417)
   
 290 
Retirement of Long-term Debt
   
 (904)
   
 (1,520)
Commercial Paper and Credit Facility Repayments
   
 (38)
   
 (819)
Principal Payments for Capital Lease Obligations
   
 (53)
   
 (53)
Dividends Paid on Common Stock
   
 (687)
   
 (668)
Dividends Paid on Cumulative Preferred Stock
   
 - 
   
 (2)
Other Financing Activities
   
 5 
   
 3 
Net Cash Flows Used for Financing Activities
   
 (409)
   
 (1,119)
             
Net Increase in Cash and Cash Equivalents
   
 222 
   
 252 
Cash and Cash Equivalents at Beginning of Period
   
 221 
   
 294 
Cash and Cash Equivalents at End of Period
 
$
 443 
 
$
 546 
             
SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 698 
 
$
 716 
Net Cash Paid (Received) for Income Taxes
   
 (44)
   
 (119)
Noncash Acquisitions Under Capital Leases
   
 46 
   
 39 
Construction Expenditures Included in Current Liabilities as of September 30,
   
 325 
   
 304 
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,
   
 43 
   
 - 
Noncash Assumption of Liabilities Related to Acquisitions
   
 56 
   
 - 
Noncash Increase in Long-term Debt Through the Fort Wayne Lease Settlement
   
 - 
   
 27 
             
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 and Impairments
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 nine months ended September 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 September 30, 2012 and 2011 were $35 million and $33 million, respectively, and for the nine months ended September 30, 2012 and 2011 were $126 million and $97 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 September 30, 2012 and 2011 were $16 million and $16 million, respectively, and for the nine months ended September 30, 2012 and 2011 were $31 million and $46 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 September 30, 2012 and 2011 were $23 million and $6 million, respectively, and for the nine months ended September 30, 2012 and 2011 were $82 million and $49 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 $2.3 billion and $1.7 billion as of September 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 as of September 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
 
September 30, 2012
 
(in millions)
 
                                   
                             
TCC
 
     
SWEPCo
 
I&M
 
Protected Cell
     
Transition
 
     
Sabine
DCC Fuel
of EIS
AEP Credit
 
Funding
 
ASSETS
                               
Current Assets
 
$
 71 
 
$
 155 
 
$
 137 
 
$
 895 
 
$
 222 
 
Net Property, Plant and Equipment
   
 175 
   
 208 
   
 - 
   
 - 
   
 - 
 
Other Noncurrent Assets
   
 56 
   
 113 
   
 5 
   
 1 
   
 2,231 
(a)
Total Assets
 
$
 302 
 
$
 476 
 
$
 142 
 
$
 896 
 
$
 2,453 
 
                                   
LIABILITIES AND EQUITY
                               
Current Liabilities
 
$
 45 
 
$
 128 
 
$
 50 
 
$
 850 
 
$
 293 
 
Noncurrent Liabilities
   
 257 
   
 348 
   
 71 
   
 1 
   
 2,142 
 
Equity
   
 - 
   
 - 
   
 21 
   
 45 
   
 18 
 
Total Liabilities and Equity
 
$
 302 
 
$
 476 
 
$
 142 
 
$
 896 
 
$
 2,453 
 

               (a)       Includes an intercompany item eliminated in consolidation of $90 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 September 30, 2012 and 2011 were $20 million and $18 million, respectively and for the nine months ended September 30, 2012 and 2011 were $54 million and $47 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:

 
September 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
  -     53     -     52
                       
Total Investment in DHLC
$ 9   $ 62   $ 9   $ 61

We and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH).  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.  The entities recover costs through regulated rates.

Based upon an analysis of the potential need for PATH, the PJM board cancelled PATH in August 2012.  In September 2012, we and FirstEnergy submitted an abandonment filing with the FERC seeking authority to recover prudently-incurred costs associated with PATH, including a return, over a sixty-month amortization period.

Our investment in PATH-WV was:

 
September 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
  13     13     10     10
                       
Total Investment in PATH-WV
$ 32   $ 32   $ 29   $ 29

 
40

 
Earnings Per Share (EPS)

Shown below are income statement amounts attributable to AEP common shareholders:

   
Three Months Ended
 
Nine Months Ended
   
September 30,
 
September 30,
Amounts Attributable to AEP Common Shareholders
 
2012
 
2011
 
2012
 
2011
   
(in millions)
Income Before Extraordinary Item
  $ 487   $ 655   $ 1,238   $ 1,360
Extraordinary Item, Net of Tax
    -     273     -     273
Net Income
  $ 487   $ 928   $ 1,238   $ 1,633

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 September 30,
   
2012
   
2011
   
(in millions, except per share data)
       
$/share
       
$/share
Earnings Attributable to AEP Common Shareholders
  $ 487           $ 928      
                           
Weighted Average Number of Basic Shares Outstanding
    485.0     $ 1.00       482.5     $ 1.92
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
    485.4     $ 1.00       482.8     $ 1.92

   
Nine Months Ended September 30,
   
2012
   
2011
   
(in millions, except per share data)
       
$/share
       
$/share
Earnings Attributable to AEP Common Shareholders
  $ 1,238           $ 1,633      
                           
Weighted Average Number of Basic Shares Outstanding
    484.4     $ 2.55       481.9     $ 3.39
Weighted Average Dilutive Effect of:
                             
Stock Options
    0.1       -       -       -
Restricted Stock Units
    0.3       -       0.2       -
Weighted Average Number of Diluted Shares Outstanding
    484.8     $ 2.55       482.1     $ 3.39

Options to purchase 10,000 shares of common stock as of September 30, 2011 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.  There were no antidilutive shares outstanding as of September 30, 2012.

Extraordinary Item

In February 2006, the PUCT issued an order that denied recovery of capacity auction true-up amounts.  Based on the 2006 PUCT order, TCC recorded the disallowance as a $421 million ($273 million, net of tax) extraordinary loss in the December 31, 2005 financial statements.  In July 2011, the Supreme Court of Texas reversed the PUCT’s February 2006 disallowance of capacity auction true-up amounts.  Based upon the Supreme Court of Texas opinion, TCC recorded a pretax gain of $421 million ($273 million, net of tax) in Extraordinary Item, Net of Tax on the condensed statements of income in the third quarter of 2011.

 
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
 
   
September 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
  $ 23     $ 24
Economic Development Rider
    13       13
Other Regulatory Assets Not Yet Being Recovered
    9       -
Regulatory Assets Currently Not Earning a Return
             
Virginia Environmental Rate Adjustment Clause
    23       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
    133       10
Virginia Deferred Wind Power Costs
    4       38
Other Regulatory Assets Not Yet Being Recovered
    29       14
Total Regulatory Assets Not Yet Being Recovered
  $ 272     $ 155

If these costs are ultimately determined not to be recoverable, it would reduce future net income and cash flows and impact financial condition.

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 result in a refund of up to $698 million, excluding carrying costs.

 
42

 
In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off 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.

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 one month after the PUCO issues an order on the 2010 SEET.  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.  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 addressed in a separate PIRR docket.

In August 2012, the PUCO ordered implementation of PIRR rates beginning September 2012.  The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin.  The August 2012 order was upheld on rehearing by the PUCO in October 2012.  As of September 30, 2012, OPCo’s net PIRR deferral was $536 million, excluding unrecognized equity carrying costs.

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 the Partnership with Ohio and the Ohio Growth Fund and an $8 million regulatory asset for 2011 storm damage, both originally recorded in the fourth quarter of 2011.

 
43

 
June 2012 – May 2015 ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that will freeze base generation rates through May 2015, adopt a 12% earnings threshold for the SEET and allow the continuation of the fuel adjustment clause.  Further, the ESP established a non-bypassable Distribution Investment Rider effective September 2012 through May 2015 to recover, with certain caps, post-August 2010 distribution investment.  The ESP also maintained recovery of several previous ESP riders and required OPCo to contribute $2 million per year during the ESP to the Ohio Growth Fund.  In addition, the ESP approved a storm damage recovery mechanism which allowed OPCo to defer the majority of the incremental distribution operation and maintenance costs from 2012 storms.  As of September 30, 2012, OPCo recorded $54 million in Regulatory Assets on the condensed balance sheets related to the 2012 storm damage.  If OPCo is not ultimately permitted to recover these storm costs, it would reduce future net income and cash flows and impact financial condition.

As part of the ESP decision, the PUCO ordered OPCo to conduct an energy-only auction for 10% of the SSO load with delivery beginning six months after the receipt of ESP and corporate separation orders and extending through December 2014.  The PUCO also ordered OPCo to conduct an energy-only auction for a total of 60% of the SSO load with delivery beginning June 2014 through May 2015.  In addition, the PUCO ordered OPCo to conduct an energy-only auction for the remaining 40% of the SSO load for delivery from January 2015 through May 2015.  Starting in June 2015, OPCo will conduct energy and capacity auctions for its entire SSO load.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of 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 June 2012 – May 2015 ESP proceeding.  In July 2012, several parties, including OPCo, requested rehearing of the July 2012 PUCO order on capacity, which was upheld by the PUCO in October 2012.

In the August 2012 PUCO order which adopted and modified the new ESP, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR is intended to provide $508 million over the ESP period and will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the deferred capacity costs.  In August 2012, the IEU filed a claim before the Supreme Court of Ohio stating, among other things, that OPCo’s collection of its capacity costs is illegal.  In September 2012, OPCo and the PUCO filed motions to dismiss IEU’s claim.  If OPCo is ultimately not permitted to fully collect its deferred capacity costs, it would reduce future net income and cash flows and impact financial condition.

In September 2012, OPCo and intervenors filed applications with the PUCO for rehearing of the August 2012 ESP order.  Rehearing of this order is pending at the PUCO.  If OPCo is ultimately not permitted to fully collect its ESP rates, including the RSR, it would reduce future net income and cash flows and impact financial condition.

Proposed Corporate Separation

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.  In October 2012, the PUCO issued an order which approved the transfer of OPCo’s generation assets at net book value to AEP Generation Resources, Inc. (AEPGenCo), a nonregulated affiliate in the Generation and Marketing segment.  AEPGenCo will also assume the associated generation liabilities.

An additional filing at the FERC related to corporate separation is expected in the fourth quarter of 2012.  Our results of operations related to generation in Ohio will be largely 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.

 
44

 
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.

Since the February 2012 PUCO order rejected the ESP modified stipulation, collection of the DIR terminated.  In August 2012, the PUCO approved a new DIR as filed in the ESP proceeding.  The DIR is capped at $86 million in 2012, $104 million in 2013, $124 million in 2014 and $52 million for the period January through May 2015, for a total of $366 million.  See the “June 2012 – May 2015 ESP Including Capacity Charge” section above.

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 August 2012, an intervenor filed with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges, which, if ordered, would be $35 million plus carrying charges.  If the Supreme Court of Ohio ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audits reports which 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 September 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 $38 million, including $20 million of unrecognized equity carrying costs.  These amounts include the carrying costs exposure of the 2009 FAC audit, which has been appealed by an intervenor to the Supreme Court of Ohio.  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.

 
45

 
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 September 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 $122 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $122 million for transmission, excluding AFUDC.  As of September 30, 2012, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital costs cap, SWEPCo has capitalized approximately $1.7 billion of expenditures, including AFUDC and capitalized interest of $296 million for generation and related transmission costs of $127 million.  As of September 30, 2012, the joint owners and SWEPCo have contractual construction obligations of approximately $42 million, including related transmission costs of $3 million.  SWEPCo’s share of the contractual construction obligations is $31 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 from the Turk Plant.  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 options.

 
46

 
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.  The Supreme Court of Texas has requested full briefing from the parties.

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 included a return on and of the Texas jurisdictional share of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operations and maintenance costs.  The filing also (a) increased depreciation expense due to the decrease in the average remaining life of the Welsh Plant to account for the change in the retirement date of the Welsh Plant, Unit 2 from 2040 to 2016, (b) proposed increased vegetation management expenditures recovered from ratepayers and (c) included a return on and of the Stall Unit as of December 2011 and associated operations and maintenance costs.

In September 2012, an Administrative Law Judge issued an order that granted the establishment of SWEPCo’s existing rates as temporary rates beginning in late January 2013, subject to true-up to the final PUCT-approved rates.  A decision from the PUCT is expected in the second quarter of 2013.  If the PUCT does not approve full cost recovery of SWEPCo’s assets, it could reduce future net income and cash flows and impact financial condition.

Flint Creek Plant Environmental Controls

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 September 30, 2012, SWEPCo has incurred $10 million related to this project, including AFUDC.  The APSC staff and the Sierra Club filed testimony that recommended the APSC deny the requested declaratory order.  A hearing at the APSC was held in October 2012 and a decision is pending from the APSC.  If SWEPCo is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

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.

 
47

 
Environmental Rate Adjustment Clause (Environmental 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.  A decision is expected in the fourth quarter of 2012.  If the Supreme Court of Virginia were to issue a favorable decision, it could increase future net income and cash flows.

Generation Rate Adjustment Clause (Generation RAC)

In January 2012, the Virginia SCC issued a generation RAC order which allowed APCo to recover $26 million annually, effective March 2012, related to recovery of the Dresden Plant.  In March 2012, APCo filed with the Virginia SCC to continue the current generation RAC rate to recover costs of the Dresden Plant through February 2014.  In August 2012, the Virginia SCC staff filed testimony that recommended a $5 million increase in the revenue requirement, including the under-recovered balance of $3 million as of April 2012.  The Virginia SCC staff also recommended an alternative proposal to not change rates and not allow APCo to accrue carrying charges on any under-recovered generation RAC balances.  A decision is expected in the fourth quarter of 2012.  If the Virginia SCC were to disallow any portion of the generation RAC, it could reduce future net income and cash flows and impact financial condition.

APCo’s Filings for an IGCC Plant

Through September 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.  If the financing order is not issued, APCo and WPCo requested that recovery of these costs be allowed in current rates.

In July 2012, the WVPSC issued an interim order that approved a settlement agreement 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.  In August 2012, APCo and WPCo filed with the WVPSC a request for a financing order to securitize $422 million related to the December 2011 under-recovered ENEC deferral balance, other ENEC-related assets and related financing costs.  Upon completion of the securitization, APCo would offset its current ENEC rates by an amount to recover the securitized balance over the securitization period.  As of September 30, 2012, APCo’s ENEC under-recovery balance of $307 million was recorded in Regulatory Assets on the condensed balance sheet, excluding $5 million of unrecognized equity carrying costs.  A hearing is scheduled for December 2012.

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%.  In October 2012, the OCC issued a final order that found PSO’s fuel and purchased power costs were prudently incurred without any disallowance and that PSO’s shareholder’s portion of off-system sales margins would remain at 25%.

 
48

 
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 an increase of approximately $25 million in annual depreciation expense.  Included in the depreciation rates increase was a decrease in the average remaining life of Tanners Creek Plant to account for the change in the retirement date of Tanners Creek Plant, Units 1-3 from 2020 to 2014.  In May 2012, I&M filed rebuttal testimony which changed the retirement date for Tanners Creek Plant, Units 1-3 to 2015.

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.  If the IURC disallows cost recovery, it could reduce future net income and cash flows and impact financial condition.

Cook Plant 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 Need and authorize I&M to defer, on an interim basis, incremental depreciation and related property tax costs, including interest, along with study, analysis and development costs until the applicable LCM costs are included in I&M’s base rates.  As of September 30, 2012, I&M has incurred $109 million related to the LCM Project, including AFUDC.

In August 2012, intervenors filed testimony in Indiana.  The Indiana Michigan Power Company Industrial Group recommended that I&M recover $229 million in a rider with the remaining costs requested in future base rate cases.  The Indiana Office of Utility Consumer Counselor (OUCC) recommended a maximum of $408 million of LCM project costs be recovered in a rider, and a maximum of $299 million for projects the OUCC believes are not related to LCM to be recovered in future base rates.  A hearing at the IURC is scheduled for January 2013.

Also in August 2012, the MPSC staff and other intervenors filed testimony in Michigan.  The recommendations ranged from the Association of Businesses Advocating Tariff Equity’s denial of deferral of costs but recovery of costs considered in future base rate cases to the Attorney General allowing recovery of LCM project costs of $848 million.  If I&M is not ultimately permitted to recover its LCM Project costs, it would reduce future net income and cash flows.

Rockport Plant Environmental Controls

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 September 30, 2012, we have incurred $48 million, including AFUDC.  If we are not ultimately permitted to recover our incurred costs, it would reduce future net income and cash flows.

 
49

 
In July 2012, certain intervenors filed testimony which recommended cost 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 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.  A hearing is scheduled for December 2012.

KPCo Rate Matters

Big Sandy Unit 2 FGD System

In May 2012, KPCo withdrew its application to the KPSC seeking approval of a Certificate of Public Convenience and Necessity to retrofit Big Sandy Unit 2 with a dry FGD system.  KPCo is currently re-evaluating its options to meet the short and long-term energy needs of its customers at the most reasonable costs.  As of September 30, 2012, KPCo has incurred $30 million related to the FGD project.  Management intends to pursue recovery of all costs related to the FGD 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.  A decision is pending from the FERC.  Not all parties have agreed to the compliance filing.

The AEP East companies provided reserves for net refunds for SECA settlements.  Based on the analysis of the May 2010 order, the compliance filing and recent settlements, 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.  Management intends to file an application with the FERC in the fourth quarter of 2012 to terminate the Interconnection Agreement.  It is unknown 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 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.

 
50

 
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 September 30, 2012, the maximum future payments for letters of credit issued under the credit facilities were $132  million with maturities ranging from October 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 September 30, 2012, SWEPCo has collected approximately $58 million through a rider for final mine closure and reclamation costs, of which $10 million is recorded in Other Current Liabilities, $7 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $41 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 September 30, 2012, there were no material liabilities recorded for any indemnifications.

 
51

 
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 September 30, 2012, the maximum potential loss for these lease agreements was approximately $18 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 September 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.

 
52

 
Alaskan Villages’ Claims

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  The plaintiffs appealed the decision.  In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court’s decision, holding that the CAA displaced Kivalina’s claims for damages.  Plaintiffs have filed a petition for rehearing by the full court.   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.

 
53

 
I&M maintains insurance through NEIL.  As of September 30, 2012, we recorded $64 million in Prepayments and Other Current Assets on our condensed balance sheets representing amounts recoverable from NEIL under the insurance policies.  Through September 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.

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.  Oral argument was held in October 2012.  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 AND IMPAIRMENTS

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.

IMPAIRMENTS

2012

Turk Plant (Utility Operations segment)

In 2012, SWEPCo recorded a pretax write-off of $13 million in Asset Impairments and Other Related Charges on the condensed statements of income related to unrecoverable construction costs subject to the Texas capital costs cap portion of the Turk Plant.

 
54

 
2011

Muskingum River Plant Unit 5 FGD Project (MR5) (Utility Operations segment)

In September 2011, subsequent to the stipulation agreement filed with the PUCO, management determined that OPCo was not likely to complete the previously suspended MR5 project and that the project’s preliminary engineering costs were no longer probable of being recovered.  As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $42 million in Asset Impairments and Other Related Charges on the condensed statements of income.

Sporn Plant Unit 5 (Utility Operations segment)

In the third quarter of 2011, management decided to no longer offer the output of Sporn Unit 5 into the PJM market.  Sporn Unit 5 is not expected to operate in the future, resulting in the removal of Sporn Unit 5 from the Interconnection Agreement.  As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $48 million in Asset Impairments and Other Related Charges on the condensed statements of income.

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 nine months ended September 30, 2012 and 2011:

     
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
 
2012
 
2011
 
2012
 
2011
 
 
(in millions)
 
Service Cost
$ 19   $ 18   $ 12   $ 11  
Interest Cost
  56     59     26     27  
Expected Return on Plan Assets
  (80 )   (79 )   (26 )   (27 )
Amortization of Transition Obligation
  -     -     1     1  
Amortization of Prior Service Cost (Credit)
  -     1     (5 )   (1 )
Amortization of Net Actuarial Loss
  42     31     14     8  
Net Periodic Benefit Cost
$ 37   $ 30   $ 22   $ 19  

     
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2012
 
2011
 
2012
 
2011
 
 
(in millions)
 
Service Cost
$ 57   $ 54   $ 35   $ 32  
Interest Cost
  167     178     78     81  
Expected Return on Plan Assets
  (239 )   (236 )   (76 )   (81 )
Amortization of Transition Obligation
  -     -     1     1  
Amortization of Prior Service Cost (Credit)
  -     1     (14 )   (1 )
Amortization of Net Actuarial Loss
  117     92     43     23  
Net Periodic Benefit Cost
$ 102   $ 89   $ 67   $ 55  

 
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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 and 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 nine months ended September 30, 2012 and 2011 and balance sheet information as of September 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 September 30, 2012
                                         
Revenues from:
                                         
   
External Customers
 
$
 3,811 
 
$
 3 
 
$
 142 
 
$
 194 
 
$
 6 
 
$
 - 
 
$
 4,156 
   
Other Operating Segments
   
 28 
   
 7 
   
 5 
   
 - 
   
 4 
   
 (44)
   
 - 
Total Revenues
 
$
 3,839 
 
$
 10 
 
$
 147 
 
$
 194 
 
$
 10 
 
$
 (44)
 
$
 4,156 
                                               
Net Income (Loss)
 
$
 471 
 
$
 14 
 
$
 (1)
 
$
 10 
 
$
 (6)
 
$
 - 
 
$
 488 
                                               
                   
Nonutility Operations
                 
                         
Generation
                 
     
Utility
 
Transmission
AEP River
and
All Other
Reconciling
   
     
Operations
 
Operations
Operations
Marketing
(a)
 Adjustments
Consolidated
       
(in millions)
Three Months Ended September 30, 2011
                                         
Revenues from:
                                         
   
External Customers
 
$
 4,044 
 
$
 - 
 
$
 177 
 
$
 106 
 
$
 6 
 
$
 - 
 
$
 4,333 
   
Other Operating Segments
   
 30 
   
 3 
   
 6 
   
 - 
   
 4 
   
 (43)
   
 - 
Total Revenues
 
$
 4,074 
 
$
 3 
 
$
 183 
 
$
 106 
 
$
 10 
 
$
 (43)
 
$
 4,333 
                                               
Income (Loss) Before Extraordinary
                                         
 
Item
 
$
 633 
 
$
 9 
 
$
 17 
 
$
 8 
 
$
 (10)
 
$
 - 
 
$
 657 
Extraordinary Item, Net of Tax
   
 273 
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
   
 273 
Net Income (Loss)
 
$
 906 
 
$
 9 
 
$
 17 
 
$
 8 
 
$
 (10)
 
$
 - 
 
$
 930 

                   
Nonutility Operations
                 
                         
Generation
                 
     
Utility
 
Transmission
AEP River
and
All Other
Reconciling
   
     
Operations
 
Operations
Operations
Marketing
(a)
 Adjustments
Consolidated
       
(in millions)
Nine Months Ended September 30, 2012
                                         
Revenues from:
                                         
   
External Customers
 
$
 10,407 
 
$
 5 
 
$
 477 
 
$
 427 
 
$
 16 
 
$
 - 
 
$
 11,332 
   
Other Operating Segments
   
 75 
   
 10 
   
 16 
   
 - 
   
 7 
   
 (108)
   
 - 
Total Revenues
 
$
 10,482 
 
$
 15 
 
$
 493 
 
$
 427 
 
$
 23 
 
$
 (108)
 
$
 11,332 
                                               
Net Income (Loss)
 
$
 1,220 
 
$
 31 
 
$
 11 
 
$
 4 
 
$
 (25)
 
$
 - 
 
$
 1,241 
                                               
                   
Nonutility Operations
                 
                         
Generation
                 
     
Utility
 
Transmission
AEP River
and
All Other
Reconciling
   
     
Operations
 
Operations
Operations
Marketing
(a)
 Adjustments
Consolidated
       
(in millions)
Nine Months Ended September 30, 2011
                                         
Revenues from:
                                         
   
External Customers
 
$
 10,900 
 
$
 1 
 
$
 506 
 
$
 247 
 
$
 18 
 
$
 - 
 
$
 11,672 
   
Other Operating Segments
   
 86 
   
 2 
   
 15 
   
 1 
   
 7 
   
 (111)
   
 - 
Total Revenues
 
$
 10,986 
 
$
 3 
 
$
 521 
 
$
 248 
 
$
 25 
 
$
 (111)
 
$
 11,672 
                                               
Income (Loss) Before Extraordinary
                                         
 
Item
 
$
 1,357 
 
$
 19 
 
$
 23 
 
$
 20 
 
$
 (54)
 
$
 - 
 
$
 1,365 
Extraordinary Item, Net of Tax
   
 273 
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
   
 273 
Net Income (Loss)
 
$
 1,630 
 
$
 19 
 
$
 23 
 
$
 20 
 
$
 (54)
 
$
 - 
 
$
 1,638 

 
57

 
               
Nonutility Operations
                 
                     
Generation
       
Reconciling
     
 
Utility
 
Transmission
 
AEP River
 
and
 
All Other
 
 Adjustments
     
 
Operations
 
Operations
 
Operations
 
Marketing
 
(a)
 
(b)
 
Consolidated
   
(in millions)
September 30, 2012
                                         
Total Property, Plant and Equipment
 
$
 55,859 
 
$
 604 
 
$
 632 
 
$
 619 
 
$
 11 
 
$
 (266)
 
$
 57,459 
Accumulated Depreciation and
                                         
Amortization
   
 18,986 
   
 2 
   
 156 
   
 240 
   
 10 
   
 (68)
   
 19,326 
Total Property, Plant and
                                         
 Equipment - Net
 
$
 36,873 
 
$
 602 
 
$
 476 
 
$
 379 
 
$
 1 
 
$
 (198)
 
$
 38,133 
                                           
Total Assets
 
$
 51,124 
 
$
 1,008 
 
$
 643 
 
$
 1,022 
 
$
 16,885 
 
$
 (16,839)
(c)
$
 53,843 
                                           
               
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.
 
 
58

 

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

Risk Management Strategies

Our strategy surrounding the use of derivative instruments primarily focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  Our risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact.  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 September 30, 2012 and December 31, 2011:

Notional Volume of Derivative Instruments
                   
     
Volume
   
     
September 30,
 
December 31,
 
Unit of
   
2012 
 
2011 
 
Measure
Primary Risk Exposure
 
(in millions)
 
Commodity:
               
 
Power
   
 617 
   
 609 
 
MWhs
 
Coal
   
 15 
   
 21 
 
Tons
 
Natural Gas
   
 123 
   
 100 
 
MMBtus
 
Heating Oil and Gasoline
   
 5 
   
 6 
 
Gallons
 
Interest Rate
 
$
 258 
 
$
 226 
 
USD
                   
Interest Rate and Foreign Currency
 
$
 703 
 
$
 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.

 
59

 
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.

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 September 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 $48 million and $133 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

 
60

 
The following tables represent the gross fair value impact of our derivative activity on our condensed balance sheets as of September 30, 2012 and December 31, 2011:

Fair Value of Derivative Instruments
September 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
 
$
 699 
 
$
 36 
 
$
 1 
 
$
 (561)
 
$
 175 
Long-term Risk Management Assets
   
 606 
   
 12 
   
 1 
   
 (229)
   
 390 
Total Assets
   
 1,305 
   
 48 
   
 2 
   
 (790)
   
 565 
                                 
Current Risk Management Liabilities
   
 656 
   
 35 
   
 37 
   
 (578)
   
 150 
Long-term Risk Management Liabilities
   
 460 
   
 12 
   
 2 
   
 (250)
   
 224 
Total Liabilities
   
 1,116 
   
 47 
   
 39 
   
 (828)
   
 374 
                                 
Total MTM Derivative Contract Net Assets
                             
 
(Liabilities)
 
$
 189 
 
$
 1 
 
$
 (37)
 
$
 38 
 
$
 191 
                                 
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.

 
61

 
The tables below present our activity of derivative risk management contracts for the three and nine months ended September 30, 2012 and 2011:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three and Nine Months Ended September 30, 2012 and 2011
                         
   
Three Months Ended September 30,
 
Nine Months Ended September 30,
Location of Gain (Loss)
 
2012 
 
2011 
 
2012 
 
2011 
   
(in millions)
Utility Operations Revenues
 
$
 5 
 
$
 8 
 
$
 19 
 
$
 46 
Other Revenues
   
 20 
   
 6 
   
 28 
   
 21 
Regulatory Assets (a)
   
 2 
   
 (3)
   
 (35)
   
 (3)
Regulatory Liabilities (a)
   
 (14)
   
 (2)
   
 12 
   
 8 
Total Gain (Loss) on Risk
                       
   Management Contracts
 
$
 13 
 
$
 9 
 
$
 24 
 
$
 72 
                         

(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.”

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 nine months ended September 30, 2012, we recognized gains of $1 million and $3 million, respectively, on our hedging instruments and offsetting losses of $1 million and $3 million, respectively, on our long-term debt.  During the three and nine months ended September 30, 2011, we recognized gains of $1 million and $3 million, respectively, on our hedging instruments and offsetting losses of $3 million and $6 million, respectively, on our long-term debt.  We de-designated a significant portion of our interest rate fair value hedges in the third quarter of 2011.  During the three and nine months ended September 30, 2012 and 2011, hedge ineffectiveness was immaterial.

 
62

 
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 nine months ended September 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 nine months ended September 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 nine months ended September 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 nine months ended September 30, 2012 and 2011, we designated foreign currency derivatives as cash flow hedges.

During the three and nine months ended September 30, 2012 and 2011, hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies disclosed above.

 
63

 
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 nine months ended September 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 September 30, 2012
             
Interest Rate
     
             
and Foreign
     
       
Commodity
 
Currency
 
Total
       
(in millions)
Balance in AOCI as of June 30, 2012
 
$
 (14)
 
$
 (30)
 
$
 (44)
Changes in Fair Value Recognized in AOCI
   
 16 
   
 (3)
   
 13 
Amount of (Gain) or Loss Reclassified from AOCI
                 
 
to Statement of Income/within Balance Sheet:
                 
   
Utility Operations Revenues
   
 - 
   
 - 
   
 - 
   
Other Revenues
   
 (1)
   
 - 
   
 (1)
   
Purchased Electricity for Resale
   
 - 
   
 - 
   
 - 
   
Interest Expense
   
 - 
   
 1 
   
 1 
   
Regulatory Assets (a)
   
 - 
   
 - 
   
 - 
   
Regulatory Liabilities (a)
   
 - 
   
 - 
   
 - 
Balance in AOCI as of September 30, 2012
 
$
 1 
 
$
 (32)
 
$
 (31)
                       
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended September 30, 2011
             
Interest Rate
     
             
and Foreign
     
       
Commodity
 
Currency
 
Total
       
(in millions)
Balance in AOCI as of June 30, 2011
 
$
 12 
 
$
 5 
 
$
 17 
Changes in Fair Value Recognized in AOCI
   
 2 
   
 (21)
   
 (19)
Amount of (Gain) or Loss Reclassified from AOCI
                 
 
to Statement of Income/within Balance Sheet:
                 
   
Utility Operations Revenues
   
 1 
   
 - 
   
 1 
   
Other Revenues
   
 (1)
   
 - 
   
 (1)
   
Purchased Electricity for Resale
   
 (2)
   
 - 
   
 (2)
   
Interest Expense
   
 - 
   
 1 
   
 1 
   
Regulatory Assets (a)
   
 - 
   
 - 
   
 - 
   
Regulatory Liabilities (a)
   
 - 
   
 - 
   
 - 
Balance in AOCI as of September 30, 2011
 
$
 12 
 
$
 (15)
 
$
 (3)

 
64

 
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Nine Months Ended September 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
   
 (7)
   
 (15)
   
 (22)
Amount of (Gain) or Loss Reclassified from AOCI
                 
 
to Statement of Income/within Balance Sheet:
                 
   
Utility Operations Revenues
   
 - 
   
 - 
   
 - 
   
Other Revenues
   
 (4)
   
 - 
   
 (4)
   
Purchased Electricity for Resale
   
 13 
   
 - 
   
 13 
   
Interest Expense
   
 - 
   
 3 
   
 3 
   
Regulatory Assets (a)
   
 2 
   
 - 
   
 2 
   
Regulatory Liabilities (a)
   
 - 
   
 - 
   
 - 
Balance in AOCI as of September 30, 2012
 
$
 1 
 
$
 (32)
 
$
 (31)
                       
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Nine Months Ended September 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
   
 7 
   
 (22)
   
 (15)
Amount of (Gain) or Loss Reclassified from AOCI
                 
 
to Statement of Income/within Balance Sheet:
                 
   
Utility Operations Revenues
   
 3 
   
 - 
   
 3 
   
Other Revenues
   
 (3)
   
 - 
   
 (3)
   
Purchased Electricity for Resale
   
 (3)
   
 - 
   
 (3)
   
Interest Expense
   
 - 
   
 3 
   
 3 
   
Regulatory Assets (a)
   
 1 
   
 - 
   
 1 
   
Regulatory Liabilities (a)
   
 - 
   
 - 
   
 - 
Balance in AOCI as of September 30, 2011
 
$
 12 
 
$
 (15)
 
$
 (3)

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

 
65

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

Impact of Cash Flow Hedges on the Condensed Balance Sheet
September 30, 2012
                       
             
Interest Rate
     
             
and Foreign
     
       
Commodity
 
Currency
 
Total
       
(in millions)
Hedging Assets (a)
 
$
 33 
 
$
 - 
 
$
 33 
Hedging Liabilities (a)
   
 32 
   
 39 
   
 71 
AOCI Gain (Loss) Net of Tax
   
 1 
   
 (32)
   
 (31)
Portion Expected to be Reclassified to Net
                 
 
Income During the Next Twelve Months
   
 - 
   
 (4)
   
 (4)
                       
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 September 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 36 months.

Credit Risk

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

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

 
66

 
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 September 30, 2012 and December 31, 2011:

     
September 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
   
 44 
   
 39 
Amount Attributable to RTO and ISO Activities
   
 42 
   
 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 September 30, 2012 and December 31, 2011:

   
September 30,
 
December 31,
   
2012 
 
2011 
   
(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual
           
   Netting Arrangements
 
$
 519 
 
$
 515 
Amount of Cash Collateral Posted
   
 3 
   
 56 
Additional Settlement Liability if Cross Default Provision is Triggered
   
 329 
   
 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.  Our market risk oversight staff independently monitors our valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures.  The CORC consists of our Chief Operation Officer, Chief Financial Officer, Senior Vice President of Commercial Operations and Chief Risk Officer.

 
67

 
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, FTRs and counterparty credit risk 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.  A significant portion of our Level 3 instruments 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 September 30, 2012 and December 31, 2011 are summarized in the following table:

   
September 30, 2012
 
December 31, 2011
   
Book Value
 
Fair Value
 
Book Value
 
Fair Value
   
(in millions)
Long-term Debt
 
$
 17,227 
 
$
 20,457 
 
$
 16,516 
 
$
 19,259 

 
68

 
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:

       
September 30, 2012
 
           
Gross
 
Gross
 
Estimated
 
           
 Unrealized
 
Unrealized
 
 Fair
Other Temporary Investments
 
Cost
 
Gains
 
Losses
 
Value
       
(in millions)
 
Restricted Cash (a)
 
$
 197 
 
$
 - 
 
$
 - 
 
$
 197 
 
Fixed Income Securities:
                         
 
Mutual Funds
   
 64 
   
 1 
   
 - 
   
 65 
 
Equity Securities - Mutual Funds
   
 11 
   
 5 
   
 - 
   
 16 
 
Total Other Temporary Investments
 
$
 272 
 
$
 6 
 
$
 - 
 
$
 278 
 
                               
       
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 nine months ended September 30, 2012 and 2011:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2012 
 
2011 
 
2012 
 
2011 
 
(in millions)
Proceeds from Investment Sales
$
 - 
 
$
 21 
 
$
 - 
 
$
 268 
Purchases of Investments
 
 - 
   
 - 
   
 1 
   
 153 
Gross Realized Gains on Investment Sales
 
 - 
   
 4 
   
 - 
   
 4 
Gross Realized Losses on Investment Sales
 
 - 
   
 - 
   
 - 
   
 - 

As of September 30, 2012 and December 31, 2011, we had no Other Temporary Investments with an unrealized loss position.  As of September 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.

 
69

 
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 nine months ended September 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 September 30, 2012
           
       
(in millions)
Balance in AOCI as of June 30, 2012
 
$
 3 
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 September 30, 2012
 
$
 4 

Total Accumulated Other Comprehensive Income (Loss) Activity for Other Temporary Investments
Nine Months Ended September 30, 2012
           
       
(in millions)
Balance in AOCI as of December 31, 2011
 
$
 2 
Changes in Fair Value Recognized in AOCI
   
 2 
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income:
     
   
Interest Income
   
 - 
Balance in AOCI as of September 30, 2012
 
$
 4 

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.

 
70

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

     
September 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
 
$
 13 
 
$
 - 
 
$
 - 
 
$
 18 
 
$
 - 
 
$
 - 
Fixed Income Securities:
                                   
 
United States Government
   
 693 
   
 108 
   
 (1)
   
 544 
   
 61 
   
 (1)
 
Corporate Debt
   
 36 
   
 6 
   
 (1)
   
 54 
   
 5 
   
 (2)
 
State and Local Government
   
 226 
   
 1 
   
 (1)
   
 330 
   
 - 
   
 (2)
 
  Subtotal Fixed Income Securities
 
 955 
   
 115 
   
 (3)
   
 928 
   
 66 
   
 (5)
Equity Securities - Domestic
   
 732 
   
 291 
   
 (78)
   
 646 
   
 215 
   
 (80)
Spent Nuclear Fuel and
                                   
 
Decommissioning Trusts
 
$
 1,700 
 
$
 406 
 
$
 (81)
 
$
 1,592 
 
$
 281 
 
$
 (85)

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

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2012 
 
2011 
 
2012 
 
2011 
 
(in millions)
Proceeds from Investment Sales
$
 182 
 
$
 361 
 
$
 699 
 
$
 826 
Purchases of Investments
 
 199 
   
 379 
   
 744 
   
 871 
Gross Realized Gains on Investment Sales
 
 2 
   
 18 
   
 7 
   
 30 
Gross Realized Losses on Investment Sales
 
 1 
   
 12 
   
 3 
   
 21 

The adjusted cost of fixed income securities was $840 million and $862 million as of September 30, 2012 and December 31, 2011, respectively.  The adjusted cost of equity securities was $441 million and $431 million as of September 30, 2012 and December 31, 2011, respectively.

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

 
Fair Value of
 
 
Fixed Income
 
 
Securities
 
 
(in millions)
 
Within 1 year
$ 136  
1 year – 5 years
  357  
5 years – 10 years
  265  
After 10 years
  197  
Total
$ 955  

 
71

 
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 September 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
September 30, 2012
                       
     
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in millions)
                                 
Cash and Cash Equivalents (a) (e)
$
 20 
 
$
 1 
 
$
 - 
 
$
 422 
 
$
 443 
                                 
Other Temporary Investments
                           
Restricted Cash (a) (e)
 
 183 
   
 5 
   
 - 
   
 9 
   
 197 
Fixed Income Securities:
                           
 
Mutual Funds
 
 65 
   
 - 
   
 - 
   
 - 
   
 65 
Equity Securities - Mutual Funds (b)
 
 16 
   
 - 
   
 - 
   
 - 
   
 16 
Total Other Temporary Investments
 
 264 
   
 5 
   
 - 
   
 9 
   
 278 
                                 
Risk Management Assets
                           
Risk Management Commodity Contracts (c) (f)
 
 47 
   
 1,076 
   
 166 
   
 (778)
   
 511 
Cash Flow Hedges:
                           
 
Commodity Hedges (c)
 
 9 
   
 37 
   
 2 
   
 (15)
   
 33 
Fair Value Hedges
 
 - 
   
 2 
   
 - 
   
 - 
   
 2 
De-designated Risk Management Contracts (d)
 
 - 
   
 - 
   
 - 
   
 19 
   
 19 
Total Risk Management Assets
 
 56 
   
 1,115 
   
 168 
   
 (774)
   
 565 
                                 
Spent Nuclear Fuel and Decommissioning Trusts
                           
Cash and Cash Equivalents (e)
 
 - 
   
 5 
   
 - 
   
 8 
   
 13 
Fixed Income Securities:
                           
 
United States Government
 
 - 
   
 693 
   
 - 
   
 - 
   
 693 
 
Corporate Debt
 
 - 
   
 36 
   
 - 
   
 - 
   
 36 
 
State and Local Government
 
 - 
   
 226 
   
 - 
   
 - 
   
 226 
   
Subtotal Fixed Income Securities
 
 - 
   
 955 
   
 - 
   
 - 
   
 955 
Equity Securities - Domestic (b)
 
 732 
   
 - 
   
 - 
   
 - 
   
 732 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 732 
   
 960 
   
 - 
   
 8 
   
 1,700 
                                 
Total Assets
$
 1,072 
 
$
 2,081 
 
$
 168 
 
$
 (335)
 
$
 2,986 
                                 
Liabilities:
                           
                                 
Risk Management Liabilities
                           
Risk Management Commodity Contracts (c) (f)
$
 42 
 
$
 994 
 
$
 64 
 
$
 (797)
 
$
 303 
Cash Flow Hedges:
                           
 
Commodity Hedges (c)
 
 - 
   
 47 
   
 - 
   
 (15)
   
 32 
 
Interest Rate/Foreign Currency Hedges
 
 - 
   
 39 
   
 - 
   
 - 
   
 39 
Total Risk Management Liabilities
$
 42 
 
$
 1,080 
 
$
 64 
 
$
 (812)
 
$
 374 

 
72

 


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 September 30, 2012 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $12 million in periods 2013-2015 and ($7) million in periods 2016-2018;  Level 2 matures $59 million in periods 2013-2015, $14 million in periods 2016-2017 and $9 million in periods 2018-2030;  Level 3 matures $7 million in 2012, $35 million in periods 2013-2015, $31 million in periods 2016-2017 and $29 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 nine months ended September 30, 2012 and 2011.

 
73

 
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 September 30, 2012
 
Assets (Liabilities)
     
(in millions)
Balance as of June 30, 2012
 
$
 97 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
   
 (5)
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
   
 5 
Purchases, Issuances and Settlements (c)
   
 4 
Transfers into Level 3 (d) (f)
   
 (3)
Transfers out of Level 3 (e) (f)
   
 (1)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
   
 - 
Balance as of September 30, 2012
 
$
 104 

     
Net Risk Management
Three Months Ended September 30, 2011
 
Assets (Liabilities)
     
(in millions)
Balance as of June 30, 2011
 
$
 77 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
   
 (16)
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)
   
 3 
Transfers into Level 3 (d) (f)
   
 5 
Transfers out of Level 3 (e) (f)
   
 (1)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
   
 1 
Balance as of September 30, 2011
 
$
 64 

     
Net Risk Management
Nine Months Ended September 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)
   
 (16)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
     
 
Relating to Assets Still Held at the Reporting Date (a)
   
 20 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
   
 2 
Purchases, Issuances and Settlements (c)
   
 33 
Transfers into Level 3 (d) (f)
   
 10 
Transfers out of Level 3 (e) (f)
   
 (21)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
   
 7 
Balance as of September 30, 2012
 
$
 104 

 
74

 


     
Net Risk Management
Nine Months Ended September 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)
   
 (11)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
     
 
Relating to Assets Still Held at the Reporting Date (a)
   
 - 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
   
 - 
Purchases, Issuances and Settlements (c)
   
 5 
Transfers into Level 3 (d) (f)
   
 9 
Transfers out of Level 3 (e) (f)
   
 (12)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
   
 (12)
Balance as of September 30, 2011
 
$
 64 

(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 September 30, 2012:

   
Fair Value
 
Valuation
 
Significant
 
Input/Range
 
Assets
 
Liabilities
Technique
Unobservable Input
 
Low
 
High
   
(in millions)
                   
Energy Contracts
 
$
 160 
 
$
 57 
 
Discounted Cash Flow
 
Forward Market Price (a)
 
$
 10.45 
 
$
 117.64 
                   
Counterparty Credit Risk (b)
   
457 
FTRs
   
 8 
   
 7 
 
Discounted Cash Flow
 
Forward Market Price (a)
   
 (7.71)
   
 9.92 
Total
 
$
 168 
 
$
 64 
                   

(a)  
Represents market prices in dollars per MWh.
(b)  
Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.

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.

 
75

 
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.

Uncertain Tax Positions

We filed the 2011 federal income tax return during the third quarter of 2012.  The return includes deductions which are not recognized in the financial statements.  This resulted in a $121 million increase in unrecognized tax benefits.  The increase in unrecognized tax benefits did not have an impact on net income, cash flows or financial condition and there was no change in the amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate.

State Tax Legislation

During the third quarter of 2012, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds and thus, the West Virginia corporate income tax rate will be reduced from 7.75% to 7.0% in 2013.  The enacted provisions will not have a material impact on net income, cash flows or financial condition.

10.  FINANCING ACTIVITIES

Long-term Debt
           
 
             
Type of Debt
 
September 30, 2012
 
December 31, 2011
   
(in millions)
Senior Unsecured Notes
 
$
 11,883 
 
$
 11,737 
Pollution Control Bonds
   
 1,958 
   
 2,112 
Notes Payable
   
 469 
   
 402 
Securitization Bonds
   
 2,316 
   
 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
   
 (36)
   
 (39)
Total Long-term Debt Outstanding
   
 17,227 
   
 16,516 
Long-term Debt Due Within One Year
   
 2,272 
   
 1,433 
Long-term Debt
 
$
 14,955 
 
$
 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 as of both September 30, 2012 and December 31, 2011 and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets.

 
76

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

         
Principal
   
Interest
   
Company
 
Type of Debt
 
Amount
   
Rate
 
Due Date
Issuances:
   
(in millions)
 
(%)
   
APCo
 
Senior Unsecured Notes
 
$
 275 
   
Variable
 
2013 
APCo
 
Pollution Control Bonds
   
 65 
   
2.25 
 
2016 
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
     
$
 1,612 
(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 $1.6 billion 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 
APCo
 
Pollution Control Bonds
   
 65 
   
2.00 
 
2012 
APCo
 
Senior Unsecured Notes
   
 250 
   
5.65 
 
2012 
I&M
 
Notes Payable
   
 14 
   
5.44 
 
2013 
I&M
 
Notes Payable
   
 11 
   
4.00 
 
2014 
I&M
 
Notes Payable
   
 15 
   
Variable
 
2015 
I&M
 
Notes Payable
   
 18 
   
Variable
 
2016 
I&M
 
Notes Payable
   
 12 
   
2.12 
 
2016 
I&M
 
Notes Payable
   
 8 
   
Variable
 
2016 
OPCo
 
Pollution Control Bonds
   
 45 
   
4.85 
 
2012 
OPCo
 
Senior Unsecured Notes
   
 150 
   
Variable
 
2012 
SWEPCo
 
Notes Payable
   
 20 
   
7.03 
 
2012 
SWEPCo
 
Notes Payable
   
 2 
   
4.58 
 
2032 
                       
Non-Registrant:
                   
AEP Subsidiaries
 
Notes Payable
   
 8 
   
Variable
 
2017 
AEP Subsidiaries
 
Notes Payable
   
 2 
   
7.59-8.03
 
2026 
AEGCo
 
Senior Unsecured Notes
   
 3 
   
6.33 
 
2037 
TCC
 
Securitization Bonds
   
 108 
   
4.98 
 
2013 
TCC
 
Securitization Bonds
   
 63 
   
5.96 
 
2013 
TCC
 
Pollution Control Bonds
   
 60 
   
1.125 
 
2012 
Total Retirements and
                   
 
Principal Payments
     
$
 904 
         

In October 2012, I&M retired $29 million of Notes Payable related to DCC Fuel.

In October 2012, AEGCo retired $4 million of 6.33% Senior Unsecured Notes due in 2037.

 
77

 
In October 2012, AEP Transmission Company, LLC issued $250 million of Senior Notes in three tranches.  The tranches are $104 million at 3.3% due in 2022, $85 million at 4% due in 2032 and $61 million at 4.73% due in 2042.

As of September 30, 2012, trustees held, on our behalf, $583 million of our reacquired Pollution Control Bonds.

Dividend Restrictions

Parent Restrictions

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

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

We have issued $315 million of Junior Subordinated Debentures.  The debentures will mature on March 1, 2063, subject to extensions to no later than March 1, 2068, and are callable at par any time on or after March 1, 2013.  We have the option to defer interest payments on the debentures for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire our common stock.  We do not anticipate any deferral of those interest payments in the foreseeable future.

Utility Subsidiaries’ Restrictions

Various 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 book 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:
                     
 
                           
     
September 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)
 
$
 696 
 
 0.24 
%
 
$
 666 
 
 0.27 
%
Commercial Paper
   
 520 
 
 0.45 
%
   
 967 
 
 0.51 
%
Line of Credit – Sabine (c)
   
 - 
 
 - 
%
   
 17 
 
 1.79 
%
Total Short-term Debt
 
$
 1,216 
       
$
 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.

 
78

 
Credit Facilities

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

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
 
Nine Months Ended
 
     
September 30,
 
September 30,
 
     
2012 
 
2011 
 
2012 
 
2011 
 
   
(dollars in millions)
 
Effective Interest Rates on Securitization of
                         
 
Accounts Receivable
   
 0.26 
%
 
 0.23 
%
 
 0.26 
%
 
 0.27 
%
Net Uncollectible Accounts Receivable
                         
 
Written Off
 
$
 8 
 
$
 11 
 
$
 21 
 
$
 28 
 

     
September 30,
 
December 31,
     
2012 
 
2011 
     
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
           
 
Less Uncollectible Accounts
 
$
 887 
 
$
 902 
Total Principal Outstanding
   
 696 
   
 666 
Delinquent Securitized Accounts Receivable
   
 41 
   
 38 
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable
   
 22 
   
 18 
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable
   
 236 
   
 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.

 
79

 
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 in early 2013.  The severance program provides two weeks of base pay for every year of service along with other severance benefits.

We recorded charges to expense in 2012 related to the sustainable cost reductions initiative.

   
Total
 
   
(in millions)
 
Incurred
 
$
 14 
 
Settled
   
 (12)
 
Remaining Balance as of September 30, 2012
 
$
 2 
 

These expenses relate primarily to severance benefits.  They are included primarily in Other Operation on the condensed statements of income and Other Current Liabilities on the condensed balance sheets.  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 net income, cash flows and financial condition.


 
80

 







APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

 
81

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

EXECUTIVE OVERVIEW

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.  In August 2012, APCo and WPCo filed with the WVPSC a request for a financing order to securitize $422 million related to APCo’s December 2011 under-recovered ENEC deferral balance, other ENEC-related assets and related financing costs.  A hearing is scheduled in December 2012.

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 fourth quarter of 2012.

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 150.  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 207 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
                     
                           
KWh Sales/Degree Days
                     
 
Summary of KWh Energy Sales
                     
   
Three Months Ended
 
Nine Months Ended
   
September 30,
 
September 30,
 
2012
 
2011 
 
2012
 
2011 
   
(in millions of KWhs)
Retail:
                 
Residential
 
 2,741 
 
 2,854 
   
 8,375 
 
 9,180 
Commercial
 
 1,804 
 
 1,861 
   
 5,112 
 
 5,254 
Industrial
 
 2,712 
 
 2,738 
   
 8,018 
 
 8,056 
Miscellaneous
 
 202 
 
 204 
   
 604 
 
 617 
Total Retail (a)
 
 7,459 
 
 7,657 
   
 22,109 
 
 23,107 
                   
Wholesale
 
 2,745 
 
 3,072 
   
 5,618 
 
 7,235 
                   
Total KWhs
 
 10,204 
 
 10,729 
   
 27,727 
 
 30,342 
                     
(a) Represents energy delivered to distribution customers.

 
82

 
Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

Summary of Heating and Cooling Degree Days
                         
   
Three Months Ended
 
Nine Months Ended
   
September 30,
September 30,
   
2012 
 
2011 
 
2012 
 
2011 
   
(in degree days)
Actual - Heating (a)
 
 3 
   
 3 
   
 986 
   
 1,389 
Normal - Heating (b)
 
 3 
   
 3 
   
 1,443 
   
 1,440 
                         
Actual - Cooling (c)
 
 892 
   
 955 
   
 1,336 
   
 1,425 
Normal - Cooling (b)
 
 817 
   
 807 
   
 1,178 
   
 1,161 
                         
(a)
Eastern Region heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.

 
83

 

Third Quarter of 2012 Compared to Third Quarter of 2011
 
Reconciliation of Third Quarter of 2011 to Third Quarter of 2012
 
Net Income
 
(in millions)
 
       
Third Quarter of 2011
  $ 53  
         
Changes in Gross Margin:
       
Retail Margins
    47  
Off-system Sales
    (3 )
Transmission Revenues
    3  
Other Revenues
    1  
Total Change in Gross Margin
    48  
         
Changes in Expenses and Other:
       
Other Operation and Maintenance
    (9 )
Depreciation and Amortization
    (18 )
Taxes Other Than Income Taxes
    (1 )
Carrying Costs Income
    (4 )
Other Income
    (4 )
Interest Expense
    1  
Total Change in Expenses and Other
    (35 )
         
Income Tax Expense
    (3 )
         
Third Quarter of 2012
  $ 63  

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 $47 million primarily due to the following:
   
·
A $24 million increase due to higher rates in Virginia.  For this increase, $18 million has a corresponding increase in Depreciation and Amortization expenses below.
   
·
A $17 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 September 2011.
   
·
A $4 million decrease in other variable electric generation expenses.
   
These increases were partially offset by:
   
·
A $5 million decrease in residential and commercial margins primarily due to lower non-weather related usage.
   
·
A $4 million decrease in weather-related usage primarily due to a 7% decrease in cooling degree days.
 
·
Margins from Off-system Sales decreased $3 million primarily due to lower market prices and reduced physical sales volumes.
 
·
Transmission Revenues increased $3 million primarily due to increased Network Integrated Transmission Service (NITS) revenue.  These revenues are offset in Other Operation and Maintenance expenses below.

 
84

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

 
·
Other Operation and Maintenance expenses increased $9 million primarily due to the following:
   
·
A $10 million increase in provisions for uncollectible accounts.
   
·
A $3 million increase in transmission expenses due to higher NITS expenses.  These expenses are offset in Transmission Revenues above.
   
These increases were partially offset by:
   
·
A $3 million decrease in generation plant maintenance expense in 2012.
 
·
Depreciation and Amortization expenses increased $18 million primarily due to:
   
·
A $10 million increase as a result of increased depreciation rates in Virginia effective February 2012.  The majority of this increase in depreciation is offset within Gross Margin.
   
·
A $4 million increase in amortization as a result of the Virginia E&R surcharge and the Virginia Environmental Rate Adjustment Clause, both effective February 2012.  This increase in amortization is offset within Gross Margin.
 
·
Carrying Costs Income decreased $4 million primarily due to lower carrying costs on the Virginia Environmental Rate Adjustment Clause and the Expanded Net Energy Charge.
 
·
Other Income decreased $4 million primarily due to:
   
·
A $2 million decrease due to interest income recorded in the third quarter of 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
   
·
A $2 million decrease in the equity component of AFUDC as a result of the completion of the Dresden Plant in January 2012.
 
·
Income Tax Expense increased $3 million primarily due to an increase in pretax book income and state income tax adjustments related to prior year tax returns partially offset by other book/tax differences which are accounted for on a flow through basis.

 
85

 
 
Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011
 
Reconciliation of Nine Months Ended September 30, 2011 to Nine Months Ended September 30, 2012
Net Income
(in millions)
       
Nine Months Ended September 30, 2011
 
$
 123 
       
Changes in Gross Margin:
     
Retail Margins
   
 141 
Off-system Sales
   
 (9)
Transmission Revenues
   
 8 
Other Revenues
   
 (2)
Total Change in Gross Margin
   
 138 
       
Changes in Expenses and Other:
     
Other Operation and Maintenance
   
 37 
Depreciation and Amortization
   
 (47)
Other Income
   
 (6)
Interest Expense
   
 4 
Total Change in Expenses and Other
   
 (12)
       
Income Tax Expense
   
 (48)
       
Nine Months Ended September 30, 2012
 
$
 201 

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 $141 million primarily due to the following:
   
·
A $67 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 September 2011.
   
·
A $56 million increase due to higher rates in Virginia and West Virginia.  For this increase, $39 million have a corresponding increase in Depreciation and Amortization expenses below.
   
·
A $22 million decrease in other variable electric generation expenses.
   
·
A $9 million deferral of additional wind purchase recovery costs as a result of the June 2012 Virginia SCC fuel factor order.
   
·
A $7 million decrease in PJM expenses.
   
These increases were partially offset by:
   
·
A $37 million decrease in weather-related usage primarily due to a 29% decrease in heating degree days.
   
·
A $14 million decrease in residential margins primarily due to lower non-weather related usage.
 
·
Margins from Off-system Sales decreased $9 million primarily due to lower market prices, reduced physical sales volumes and lower trading and marketing margins.
 
·
Transmission Revenues increased $8 million primarily due to increased NITS revenue requirements beginning in July 2011.  These NITS revenues are offset in Other Operation and Maintenance expenses below.

 
86

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

 
·
Other Operation and Maintenance expenses decreased $37 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 $15 million decrease in generation plant maintenance expenses in 2012.
   
·
A $14 million decrease due to the deferral of transmission costs for the Virginia Transmission Rate Adjustment Clause as allowed by the Virginia SCC.
   
·
A $9 million decrease in storm restoration expenses and vegetation management.
   
·
A $7 million decrease in general administrative expenses.
   
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.
   
·
An $11 million increase in transmission expenses due to higher NITS expenses.  These expenses are offset in Transmission Revenues above.
   
·
An $11 million increase in provisions for uncollectible accounts.
   
·
A $3 million increase due to expenses related to the 2012 sustainable cost reductions.
 
·
Depreciation and Amortization expenses increased $47 million primarily due to:
   
·
A $26 million increase as a result of increased depreciation rates in Virginia effective February 2012.  The majority of this increase in depreciation is offset within Gross Margin.
   
·
A $10 million increase in amortization as a result of the Virginia E&R surcharge and the Virginia Environmental Rate Adjustment Clause, both effective February 2012.  This increase in amortization is offset within Gross Margin.
   
·
A $4 million increase in depreciation as a result of Dresden Plant being placed in service in January 2012.
 
·
Other Income decreased $6 million primarily due to:
   
·
A $4 million decrease in the equity component of AFUDC as a result of the completion of the Dresden Plant in January 2012.
   
·
A $2 million decrease due to interest income recorded in the third quarter of 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
 
·
Interest Expense decreased $4 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
 
·
Income Tax Expense increased $48 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 207 for a discussion of accounting pronouncements.

 
87

 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
For the Three and Nine Months Ended September 30, 2012 and 2011
 
(in thousands)
 
(Unaudited)
 
   
   
Three Months Ended
   
Nine Months Ended
 
   
2012
   
2011
   
2012
   
2011
 
REVENUES
                       
Electric Generation, Transmission and Distribution
  $ 776,066     $ 757,366     $ 2,161,901     $ 2,175,163  
Sales to AEP Affiliates
    84,940       98,419       216,284       259,641  
Other Revenues
    3,192       2,551       7,950       6,797  
TOTAL REVENUES
    864,198       858,336       2,386,135       2,441,601  
                                 
EXPENSES
                               
Fuel and Other Consumables Used for Electric Generation
    241,448       230,318       609,985       595,597  
Purchased Electricity for Resale
    45,196       57,370       155,421       195,715  
Purchased Electricity from AEP Affiliates
    181,134       222,164       463,015       630,014  
Other Operation
    92,700       80,376       239,704       268,269  
Maintenance
    47,047       50,172       131,212       139,628  
Depreciation and Amortization
    86,636       68,749       252,188       205,492  
Taxes Other Than Income Taxes
    27,315       26,471       79,272       79,542  
TOTAL EXPENSES
    721,476       735,620       1,930,797       2,114,257  
                                 
OPERATING INCOME
    142,722       122,716       455,338       327,344  
                                 
Other Income (Expense):
                               
Interest Income
    332       2,477       1,034       3,559  
Carrying Costs Income
    3,950       7,579       17,202       17,560  
Allowance for Equity Funds Used During Construction
    443       2,451       960       4,546  
Interest Expense
    (50,071 )     (51,196 )     (153,323 )     (157,323 )
                                 
INCOME BEFORE INCOME TAX EXPENSE
    97,376       84,027       321,211       195,686  
                                 
Income Tax Expense
    34,185       31,223       120,377       72,275  
                                 
NET INCOME
    63,191       52,804       200,834       123,411  
                                 
Preferred Stock Dividend Requirements Including Capital
                               
Stock Expense
    -       199       -       599  
                                 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
  $ 63,191     $ 52,605     $ 200,834     $ 122,812  
   
The common stock of APCo is wholly-owned by AEP.
 
   
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 

 
88

 


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 
For the Three and Nine Months Ended September 30, 2012 and 2011
 
(in thousands)
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
2012
 
2011
 
2012
 
2011
 
Net Income
  $ 63,191   $ 52,804   $ 200,834   $ 123,411  
                           
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                         
Cash Flow Hedges, Net of Tax of $925 and $239 for the Three Months Ended
                         
September 30, 2012 and 2011, Respectively, and $940 and $413 for the Nine
                         
Months Ended September 30, 2012 and 2011, Respectively
    1,719     (444 )   1,746     767  
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $484
                         
and $418 for the Three Months Ended September 30, 2012 and 2011,
                         
Respectively, and $1,453 and $1,255 for the Nine Months Ended
                         
September 30, 2012 and 2011, Respectively
    899     778     2,698     2,332  
                           
TOTAL OTHER COMPREHENSIVE INCOME
    2,618     334     4,444     3,099  
                           
TOTAL COMPREHENSIVE INCOME
  $ 65,809   $ 53,138   $ 205,278   $ 126,510  
                           
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 

 
89

 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
 
COMMON SHAREHOLDER'S EQUITY
 
For the Nine Months Ended September 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  
                                         
Capital Contribution from Parent
            100,000                       100,000  
Common Stock Dividends
                    (97,500 )             (97,500 )
Preferred Stock Dividends
                    (599 )             (599 )
Gain on Reacquired Preferred Stock
            3                       3  
Subtotal – Common Shareholder's Equity
                                    2,823,583  
                                         
Net Income
                    123,411               123,411  
Other Comprehensive Income
                            3,099       3,099  
TOTAL COMMON SHAREHOLDER'S EQUITY –
                                       
SEPTEMBER 30, 2011
  $ 260,458     $ 1,575,499     $ 1,159,060     $ (44,924 )   $ 2,950,093  
                                         
TOTAL COMMON SHAREHOLDER'S EQUITY –
                                       
DECEMBER 31, 2011
  $ 260,458     $ 1,573,752     $ 1,160,747     $ (58,543 )   $ 2,936,414  
                                         
Common Stock Dividends
                    (135,000 )             (135,000 )
Subtotal – Common Shareholder's Equity
                                    2,801,414  
                                         
Net Income
                    200,834               200,834  
Other Comprehensive Income
                            4,444       4,444  
TOTAL COMMON SHAREHOLDER'S EQUITY –
                                       
SEPTEMBER 30, 2012
  $ 260,458     $ 1,573,752     $ 1,226,581     $ (54,099 )   $ 3,006,692  
                                         
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
         

 
90

 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)
 
   
2012 
 
2011 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
 1,575 
 
$
 2,317 
Advances to Affiliates
   
 22,767 
   
 22,008 
Accounts Receivable:
           
 
Customers
   
 159,974 
   
 158,382 
 
Affiliated Companies
   
 70,043 
   
 136,194 
 
Accrued Unbilled Revenues
   
 48,717 
   
 68,427 
 
Miscellaneous
   
 458 
   
 5,505 
 
Allowance for Uncollectible Accounts
   
 (10,884)
   
 (5,289)
   
Total Accounts Receivable
   
 268,308 
   
 363,219 
Fuel
   
 187,181 
   
 143,931 
Materials and Supplies
   
 102,481 
   
 101,724 
Risk Management Assets
   
 31,227 
   
 39,645 
Accrued Tax Benefits
   
 18,170 
   
 7,715 
Regulatory Asset for Under-Recovered Fuel Costs
   
 88,713 
   
 41,105 
Prepayments and Other Current Assets
   
 19,682 
   
 21,745 
TOTAL CURRENT ASSETS
   
 740,104 
   
 743,409 
             
PROPERTY, PLANT AND EQUIPMENT
           
Electric:
           
 
Generation
   
 5,577,549 
   
 5,194,967 
 
Transmission
   
 2,007,720 
   
 1,943,969 
 
Distribution
   
 2,937,648 
   
 2,845,405 
Other Property, Plant and Equipment
   
 381,235 
   
 357,326 
Construction Work in Progress
   
 283,775 
   
 565,841 
Total Property, Plant and Equipment
   
 11,187,927 
   
 10,907,508 
Accumulated Depreciation and Amortization
   
 3,162,532 
   
 2,994,016 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
   
 8,025,395 
   
 7,913,492 
                 
OTHER NONCURRENT ASSETS
           
Regulatory Assets
   
 1,416,426 
   
 1,481,193 
Long-term Risk Management Assets
   
 38,371 
   
 39,226 
Deferred Charges and Other Noncurrent Assets
   
 100,444 
   
 122,187 
TOTAL OTHER NONCURRENT ASSETS
   
 1,555,241 
   
 1,642,606 
             
TOTAL ASSETS
 
$
 10,320,740 
 
$
 10,299,507 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 
 
91

 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
September 30, 2012 and December 31, 2011
(Unaudited)
 
   
2012 
 
2011 
     
(in thousands)
CURRENT LIABILITIES
           
Advances from Affiliates
 
$
 117,574 
 
$
 198,248 
Accounts Payable:
           
 
General
   
 189,323 
   
 186,612 
 
Affiliated Companies
   
 100,849 
   
 137,376 
Long-term Debt Due Within One Year – Nonaffiliated
   
 574,678 
   
 594,525 
Risk Management Liabilities
   
 18,326 
   
 26,606 
Customer Deposits
   
 63,459 
   
 61,690 
Deferred Income Taxes
   
 33,145 
   
 14,255 
Accrued Taxes
   
 55,075 
   
 63,422 
Accrued Interest
   
 67,110 
   
 57,230 
Other Current Liabilities
   
 105,825 
   
 105,646 
TOTAL CURRENT LIABILITIES
   
 1,325,364 
   
 1,445,610 
             
NONCURRENT LIABILITIES
           
Long-term Debt – Nonaffiliated
   
 3,127,605 
   
 3,131,726 
Long-term Risk Management Liabilities
   
 20,805 
   
 12,923 
Deferred Income Taxes
   
 1,802,416 
   
 1,736,180 
Regulatory Liabilities and Deferred Investment Tax Credits
   
 601,926 
   
 576,792 
Employee Benefits and Pension Obligations
   
 283,506 
   
 302,182 
Deferred Credits and Other Noncurrent Liabilities
   
 152,426 
   
 157,680 
TOTAL NONCURRENT LIABILITIES
   
 5,988,684 
   
 5,917,483 
             
TOTAL LIABILITIES
   
 7,314,048 
   
 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
   
 1,226,581 
   
 1,160,747 
Accumulated Other Comprehensive Income (Loss)
   
 (54,099)
   
 (58,543)
TOTAL COMMON SHAREHOLDER’S EQUITY
   
 3,006,692 
   
 2,936,414 
             
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
 10,320,740 
 
$
 10,299,507 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.

 
92

 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2012 and 2011
(in thousands)
(Unaudited)
 
   
2012 
 
2011 
OPERATING ACTIVITIES
           
Net Income
 
$
 200,834 
 
$
 123,411 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
           
   
Depreciation and Amortization
   
 252,188 
   
 205,492 
   
Deferred Income Taxes
   
 84,850 
   
 184,986 
   
Carrying Costs Income
   
 (17,202)
   
 (17,560)
   
Deferral of Storm Costs
   
 (57,638)
   
 (16,977)
   
Allowance for Equity Funds Used During Construction
   
 (960)
   
 (4,546)
   
Mark-to-Market of Risk Management Contracts
   
 10,284 
   
 13,161 
   
Property Taxes
   
 20,056 
   
 19,231 
   
Fuel Over/Under-Recovery, Net
   
 61,404 
   
 (20,603)
   
Change in Other Noncurrent Assets
   
 (35,501)
   
 11,121 
   
Change in Other Noncurrent Liabilities
   
 7,155 
   
 1,014 
   
Changes in Certain Components of Working Capital:
           
     
Accounts Receivable, Net
   
 94,528 
   
 124,404 
     
Fuel, Materials and Supplies
   
 (44,007)
   
 132,579 
     
Accounts Payable
   
 (27,443)
   
 (72,682)
     
Accrued Taxes, Net
   
 (709)
   
 (54,214)
     
Other Current Assets
   
 1,754 
   
 13,023 
     
Other Current Liabilities
   
 12,128 
   
 3,984 
Net Cash Flows from Operating Activities
   
 561,721 
   
 645,824 
             
INVESTING ACTIVITIES
           
Construction Expenditures
   
 (323,866)
   
 (300,357)
Change in Advances to Affiliates, Net
   
 (759)
   
 (81,825)
Acquisitions of Assets
   
 (171)
   
 (302,217)
Other Investing Activities
   
 8,051 
   
 11,885 
Net Cash Flows Used for Investing Activities
   
 (316,745)
   
 (672,514)
             
FINANCING ACTIVITIES
           
Capital Contribution from Parent
   
 - 
   
 100,000 
Issuance of Long-term Debt – Nonaffiliated
   
 339,396 
   
 640,027 
Change in Advances from Affiliates, Net
   
 (80,674)
   
 (128,331)
Retirement of Long-term Debt – Nonaffiliated
   
 (364,868)
   
 (479,666)
Retirement of Cumulative Preferred Stock
   
 - 
   
 (8)
Principal Payments for Capital Lease Obligations
   
 (4,873)
   
 (5,546)
Dividends Paid on Common Stock
   
 (135,000)
   
 (97,500)
Dividends Paid on Cumulative Preferred Stock
   
 - 
   
 (599)
Other Financing Activities
   
 301 
   
 31 
Net Cash Flows from (Used for) Financing Activities
   
 (245,718)
   
 28,408 
             
Net Increase (Decrease) in Cash and Cash Equivalents
   
 (742)
   
 1,718 
Cash and Cash Equivalents at Beginning of Period
   
 2,317 
   
 951 
Cash and Cash Equivalents at End of Period
 
$
 1,575 
 
$
 2,669 
             
SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 137,992 
 
$
 145,969 
Net Cash Paid (Received) for Income Taxes
   
 10,870 
   
 (74,384)
Noncash Acquisitions Under Capital Leases
   
 2,338 
   
 697 
Government Grants Included in Accounts Receivable as of September 30,
   
 - 
   
 137 
Construction Expenditures Included in Current Liabilities as of September 30,
   
 59,041 
   
 60,265 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.

 
93

 

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 150.

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

 
94

 









INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES


 
95

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

EXECUTIVE OVERVIEW

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 an increase of approximately $25 million in annual depreciation expense.  Included in the depreciation rates increase was a decrease in the average remaining life of Tanners Creek Plant to account for the change in the retirement date of Tanners Creek Plant, Units 1-3 from 2020 to 2014.  In May 2012, I&M filed rebuttal testimony which changed the retirement date for Tanners Creek Plant, Units 1-3 to 2015.

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.

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 approved 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.  In September 2012, the MPSC approved I&M’s filed cost of service proposal with a minor adjustment recommended by the MPSC staff.  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.

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.  As a result, the NRC issued orders and guidance that increase procedures and testing requirements, require physical modifications to the plant and will increase future operating costs at the Cook Plant.  Management anticipates that future cumulative compliance costs will range from $40 million to $50 million.  Approximately half of this estimate is expected to be capital.  The remainder will be operating expenses that generally is expected to be incurred over the plant’s life.

 
96

 
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 increasing oversight of nuclear generating facilities.  Management is unable to predict the impact of potential future regulation of nuclear facilities.

Cook Plant 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.  A hearing at the IURC is scheduled for January 2013.  In Michigan, I&M requested that the MPSC approve a Certificate of Need and authorize I&M to defer, on an interim basis, incremental depreciation and related property tax costs, including interest, along with study, analysis and development costs until the applicable LCM costs are included in I&M’s base rates.  As of September 30, 2012, I&M has incurred $109 million related to the LCM Project, including AFUDC.  Several intervenors filed testimony with various recommendations.  If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.  See “Cook Plant Life Cycle Management Project” section of Note 2.

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 150.  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 207 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
                     
                           
KWh Sales/Degree Days
                     
 
Summary of KWh Energy Sales
                     
   
Three Months Ended
 
Nine Months Ended
   
September 30,
 
September 30,
 
2012
 
2011 
 
2012
 
2011 
   
(in millions of KWhs)
Retail:
                 
Residential
 
 1,652 
 
 1,657 
   
 4,438 
 
 4,662 
Commercial
 
 1,370 
 
 1,392 
   
 3,826 
 
 3,844 
Industrial
 
 1,887 
 
 1,920 
   
 5,684 
 
 5,635 
Miscellaneous
 
 16 
 
 14 
   
 54 
 
 52 
Total Retail (a)
 
 4,925 
 
 4,983 
   
 14,002 
 
 14,193 
                   
Wholesale
 
 3,009 
 
 3,024 
   
 7,039 
 
 7,529 
                   
Total KWhs
 
 7,934 
 
 8,007 
   
 21,041 
 
 21,722 
                     
 (a) Represents energy delivered to distribution customers.

 
97

 
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
 
Nine Months Ended
   
September 30,
September 30,
   
2012 
 
2011 
 
2012 
 
2011 
   
(in degree days)
Actual - Heating (a)
 
 19 
   
 15 
   
 1,803 
   
 2,635 
Normal - Heating (b)
 
 11 
   
 11 
   
 2,431 
   
 2,425 
                         
Actual - Cooling (c)
 
 696 
   
 767 
   
 1,095 
   
 1,071 
Normal - Cooling (b)
 
 594 
   
 585 
   
 851 
   
 837 
                         
(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.

 
98

 

Third Quarter of 2012 Compared to Third Quarter of 2011
 
Reconciliation of Third Quarter of 2011 to Third Quarter of 2012
 
Net Income
 
(in millions)
 
       
Third Quarter of 2011
  $ 52  
         
Changes in Gross Margin:
       
Retail Margins
    3  
FERC Municipals and Cooperatives
    (3 )
Off-system Sales
    (4 )
Transmission Revenues
    (2 )
Other Revenues
    (5 )
Total Change in Gross Margin
    (11 )
         
Changes in Expenses and Other:
       
Other Operation and Maintenance
    (2 )
Depreciation and Amortization
    (5 )
Taxes Other Than Income Taxes
    (2 )
Other Income
    (2 )
Interest Expense
    (2 )
Total Change in Expenses and Other
    (13 )
         
Income Tax Expense
    11  
         
Third Quarter of 2012
  $ 39  

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 increased $3 million primarily due to the following:
   
·
An $8 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 $3 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.
   
These increases were offset by:
   
·
An $11 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 $3 million primarily due to an annual rate adjustment to actual costs.
 
·
Margins from Off-system Sales decreased $4 million primarily due to lower market prices and reduced physical sales volumes.
 
·
Other Revenues decreased $5 million primarily due to decreased I&M’s River Transportation Division (RTD) revenues from barging activities as a result of the 2012 drought’s impact on river conditions.

 
99

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

 
·
Other Operation and Maintenance expenses increased $2 million primarily due to the following:
   
·
An $8 million increase in steam power expenses related to credits issued in 2011 associated with the Unit 1 fire outage.  This increase was offset by an increase in Retail Margins as discussed above.
   
·
A $6 million increase associated with the favorable resolution of a contingency in 2011.
   
·
A $5 million increase in storm restoration expenses.
   
These increases were partially offset by:
   
·
A $6 million decrease in RTD expenses from barging activities.  The decrease in RTD expense was offset by a corresponding decrease in Other Revenues from barging activities as discussed above.
   
·
A $5 million decrease in maintenance costs due to the 2011 Cook Plant outage.
   
·
A $5 million decrease in distribution and transmission maintenance expenses primarily due to decreased overhead line expenses.
 
·
Depreciation and Amortization expenses increased $5 million primarily due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant’s estimated life as approved in the Michigan base case settlement effective April 2012.  The majority of the increase in depreciation for Tanners Creek Plant’s life is offset within Gross Margin.
 
·
Income Tax Expense decreased $11 million primarily due to a decrease in pretax book income and other book/tax differences which are accounted for on a flow through basis partially offset by the regulatory accounting treatment of state income taxes.

 
100

 

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011
 
Reconciliation of Nine Months Ended September 30, 2011 to Nine Months Ended September 30, 2012
Net Income
(in millions)
         
Nine Months Ended September 30, 2011
 
$
 129 
 
         
Changes in Gross Margin:
       
Retail Margins
   
 (16)
 
FERC Municipals and Cooperatives
   
 (6)
 
Off-system Sales
   
 (12)
 
Total Change in Gross Margin
   
 (34)
 
         
Changes in Expenses and Other:
       
Other Operation and Maintenance
   
 3 
 
Depreciation and Amortization
   
 (9)
 
Other Income
   
 (2)
 
Interest Expense
   
 (3)
 
Total Change in Expenses and Other
   
 (11)
 
         
Income Tax Expense
   
 24 
 
         
Nine Months Ended September 30, 2012
 
$
 108 
 

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 $16 million primarily due to the following:
   
·
A $41 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 $10 million decrease in weather-related usage primarily due to a 32% decrease in heating degree days.
   
These decreases were partially offset by:
   
·
A $22 million increase in rate recovery primarily due to higher PJM rider revenue, Michigan base rate increases and higher Indiana Demand Side Management (DSM) revenue.  These increases are offset by a corresponding increase in other expense items as discussed below.
   
·
A $14 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 $6 million primarily due to the following:
   
·
A $13 million decrease due to an annual rate adjustment to actual costs.
   
This decrease was partially offset by:
   
·
A $7 million increase due to favorable fuel adjustments.
 
·
Margins from Off-system Sales decreased $12 million primarily due to lower market prices, reduced physical sales volumes and lower trading and marketing margins.

 
101

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

 
·
Other Operation and Maintenance expenses decreased $3 million primarily due to the following:
   
·
A $13 million decrease primarily due to maintenance outages at the Tanners Creek and Rockport plants in 2011.
   
·
A $7 million decrease in distribution operation and maintenance expenses primarily due to decreased overhead line expenses.
   
·
A $4 million decrease in RTD expenses from barging activities.  The decrease in RTD expense was partially offset by a corresponding decrease in Other Revenues from barging activities.
   
·
A $3 million decrease in transmission maintenance expenses.
     These decreases were partially offset by:
   
·
A $14 million increase in steam power expenses related to credits issued in 2011 associated with the Unit 1 fire outage.  This increase was offset by a corresponding increase in Retail Margins as discussed above.
   
·
A $6 million increase associated with the favorable resolution of a contingency in 2011.
   
·
A $4 million increase in storm restoration expenses.
   
·
A $3 million increase in customer service costs primarily due to higher DSM expenses.  The increase in DSM expenses was offset by a corresponding increase in Retail Margins as discussed above.
 
·
Depreciation and Amortization expenses increased $9 million primarily due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant’s estimated life as approved in the Michigan base case settlement effective April 2012.  The majority of the increase in depreciation for Tanners Creek Plant’s life is offset within Gross Margin.
 
·
Income Tax Expense decreased $24 million primarily due to a decrease in pretax book income, other book/tax differences which are accounted for on a flow through basis, 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 207 for a discussion of accounting pronouncements.

 
102

 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
For the Three and Nine Months Ended September 30, 2012 and 2011
 
(in thousands)
 
(Unaudited)
 
   
   
Three Months Ended
   
Nine Months Ended
 
   
2012
   
2011
   
2012
   
2011
 
REVENUES
                       
Electric Generation, Transmission and Distribution
  $ 499,078     $ 494,860     $ 1,371,070     $ 1,371,349  
Sales to AEP Affiliates
    71,324       83,417       192,967       229,187  
Other Revenues - Affiliated
    27,034       29,230       86,797       81,694  
Other Revenues - Nonaffiliated
    768       3,725       4,453       10,972  
TOTAL REVENUES
    598,204       611,232       1,655,287       1,693,202  
                                 
EXPENSES
                               
Fuel and Other Consumables Used for Electric Generation
    137,960       135,927       347,045       359,311  
Purchased Electricity for Resale
    23,399       25,671       88,797       86,759  
Purchased Electricity from AEP Affiliates
    110,891       112,416       281,032       274,967  
Other Operation
    141,728       133,327       411,218       399,384  
Maintenance
    44,308       50,341       133,817       148,877  
Depreciation and Amortization
    37,734       33,214       109,273       100,564  
Taxes Other Than Income Taxes
    21,698       19,984       62,491       62,643  
TOTAL EXPENSES
    517,718       510,880       1,433,673       1,432,505  
                                 
OPERATING INCOME
    80,486       100,352       221,614       260,697  
                                 
Other Income (Expense):
                               
Other Income
    2,049       3,944       9,159       11,306  
Interest Expense
    (26,307 )     (24,056 )     (76,733 )     (73,440 )
                                 
INCOME BEFORE INCOME TAX EXPENSE
    56,228       80,240       154,040       198,563  
                                 
Income Tax Expense
    16,974       28,538       45,755       70,048  
                                 
NET INCOME
    39,254       51,702       108,285       128,515  
                                 
Preferred Stock Dividend Requirements
    -       85       -       255  
                                 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
  $ 39,254     $ 51,617     $ 108,285     $ 128,260  
                                 
The common stock of I&M is wholly-owned by AEP.
                               
                                 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 

 
103

 
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 
For the Three and Nine Months Ended September 30, 2012 and 2011
 
(in thousands)
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
2012
 
2011
 
2012
 
2011
 
Net Income
  $ 39,254   $ 51,702   $ 108,285   $ 128,515  
                           
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                         
Cash Flow Hedges, Net of Tax of $217 and $2,633 for the Three Months Ended
                         
September 30, 2012 and 2011, Respectively, and $2,897 and $2,063 for the
                         
Nine Months Ended September 30, 2012 and 2011, Respectively
    (404 )   (4,891 )   (5,381 )   (3,832 )
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $150
                         
and $128 for the Three Months Ended September 30, 2012 and 2011,
                         
Respectively, and $450 and $383 for the Nine Months Ended September 30,
                         
2012 and 2011, Respectively
    278     238     835     711  
                           
TOTAL OTHER COMPREHENSIVE LOSS
    (126 )   (4,653 )   (4,546 )   (3,121 )
                           
TOTAL COMPREHENSIVE INCOME
  $ 39,128   $ 47,049   $ 103,739   $ 125,394  
                           
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 

 
104

 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
 
COMMON SHAREHOLDER'S EQUITY
 
For the Nine Months Ended September 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
                    (56,250 )             (56,250 )
Preferred Stock Dividends
                    (255 )             (255 )
Subtotal – Common Shareholder's Equity
                                    1,637,844  
                                         
Net Income
                    128,515               128,515  
Other Comprehensive Loss
                            (3,121 )     (3,121 )
TOTAL COMMON SHAREHOLDER'S
                                       
EQUITY – SEPTEMBER 30, 2011
  $ 56,584     $ 981,294     $ 749,370     $ (24,010 )   $ 1,763,238  
                                         
TOTAL COMMON SHAREHOLDER'S
                                       
EQUITY – DECEMBER 31, 2011
  $ 56,584     $ 980,896     $ 751,721     $ (28,221 )   $ 1,760,980  
                                         
Common Stock Dividends
                    (50,000 )             (50,000 )
Subtotal – Common Shareholder's Equity
                                    1,710,980  
                                         
Net Income
                    108,285               108,285  
Other Comprehensive Loss
                            (4,546 )     (4,546 )
TOTAL COMMON SHAREHOLDER'S
                                       
EQUITY – SEPTEMBER 30, 2012
  $ 56,584     $ 980,896     $ 810,006     $ (32,767 )   $ 1,814,719  
                                         
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 

 
105

 
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)
 
   
2012 
 
2011 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
 767 
 
$
 1,020 
Advances to Affiliates
   
 284,768 
   
 95,714 
Accounts Receivable:
           
 
Customers
   
 63,685 
   
 72,461 
 
Affiliated Companies
   
 76,472 
   
 90,980 
 
Accrued Unbilled Revenues
   
 20,229 
   
 14,780 
 
Miscellaneous
   
 13,488 
   
 22,685 
 
Allowance for Uncollectible Accounts
   
 (133)
   
 (1,750)
   
Total Accounts Receivable
   
 173,741 
   
 199,156 
Fuel
   
 53,587 
   
 52,979 
Materials and Supplies
   
 165,284 
   
 175,924 
Risk Management Assets
   
 28,502 
   
 32,152 
Accrued Tax Benefits
   
 11,413 
   
 38,425 
Deferred Cook Plant Fire Costs
   
 64,448 
   
 63,809 
Prepayments and Other Current Assets
   
 60,657 
   
 35,395 
TOTAL CURRENT ASSETS
   
 843,167 
   
 694,574 
             
PROPERTY, PLANT AND EQUIPMENT
           
Electric:
           
 
Generation
   
 3,929,486 
   
 3,932,472 
 
Transmission
   
 1,272,008 
   
 1,224,786 
 
Distribution
   
 1,527,157 
   
 1,481,608 
Other Property, Plant and Equipment (Including Nuclear Fuel and Coal Mining)
   
 683,879 
   
 709,558 
Construction Work in Progress
   
 237,109 
   
 236,096 
Total Property, Plant and Equipment
   
 7,649,639 
   
 7,584,520 
Accumulated Depreciation, Depletion and Amortization
   
 3,224,298 
   
 3,179,920 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
   
 4,425,341 
   
 4,404,600 
             
OTHER NONCURRENT ASSETS
           
Regulatory Assets
   
 581,048 
   
 602,979 
Spent Nuclear Fuel and Decommissioning Trusts
   
 1,699,691 
   
 1,591,732 
Long-term Risk Management Assets
   
 26,304 
   
 29,362 
Deferred Charges and Other Noncurrent Assets
   
 95,026 
   
 69,309 
TOTAL OTHER NONCURRENT ASSETS
   
 2,402,069 
   
 2,293,382 
             
TOTAL ASSETS
 
$
 7,670,577 
 
$
 7,392,556 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 
 
106

 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
September 30, 2012 and December 31, 2011
(dollars in thousands)
(Unaudited)
 
       
2012 
 
2011 
CURRENT LIABILITIES
           
Accounts Payable:
           
 
General
 
$
 95,611 
 
$
 113,063 
 
Affiliated Companies
   
 65,865 
   
 81,102 
Long-term Debt Due Within One Year – Nonaffiliated
           
 
(September 30, 2012 and December 31, 2011 Amounts Include $126,570 and
           
 
$101,620, Respectively, Related to DCC Fuel)
   
 304,694 
   
 279,075 
Risk Management Liabilities
   
 33,188 
   
 16,980 
Customer Deposits
   
 30,570 
   
 30,696 
Accrued Taxes
   
 43,963 
   
 65,233 
Accrued Interest
   
 22,372 
   
 27,798 
Other Current Liabilities
   
 154,827 
   
 117,879 
TOTAL CURRENT LIABILITIES
   
 751,090 
   
 731,826 
             
NONCURRENT LIABILITIES
           
Long-term Debt – Nonaffiliated
   
 1,804,936 
   
 1,778,600 
Long-term Risk Management Liabilities
   
 14,829 
   
 18,871 
Deferred Income Taxes
   
 983,791 
   
 925,712 
Regulatory Liabilities and Deferred Investment Tax Credits
   
 974,541 
   
 875,202 
Asset Retirement Obligations
   
 1,052,773 
   
 1,013,122 
Deferred Credits and Other Noncurrent Liabilities
   
 273,898 
   
 288,243 
TOTAL NONCURRENT LIABILITIES
   
 5,104,768 
   
 4,899,750 
             
TOTAL LIABILITIES
   
 5,855,858 
   
 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
   
 810,006 
   
 751,721 
Accumulated Other Comprehensive Income (Loss)
   
 (32,767)
   
 (28,221)
TOTAL COMMON SHAREHOLDER’S EQUITY
   
 1,814,719 
   
 1,760,980 
             
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
 7,670,577 
 
$
 7,392,556 
     
 
   
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.

 
107

 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2012 and 2011
(in thousands)
(Unaudited)
 
   
2012 
 
2011 
OPERATING ACTIVITIES
           
Net Income
 
$
 108,285 
 
$
 128,515 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
           
   
Depreciation and Amortization
   
 109,273 
   
 100,564 
   
Deferred Income Taxes
   
 46,365 
   
 71,121 
   
Amortization of Incremental Nuclear Refueling Outage Expenses, Net
   
 2,598 
   
 13,544 
   
Allowance for Equity Funds Used During Construction
   
 (6,931)
   
 (11,790)
   
Mark-to-Market of Risk Management Contracts
   
 9,882 
   
 9,014 
   
Amortization of Nuclear Fuel
   
 100,435 
   
 107,801 
   
Fuel Over/Under-Recovery, Net
   
 2,867 
   
 (4,676)
   
Change in Other Noncurrent Assets
   
 14,214 
   
 15,975 
   
Change in Other Noncurrent Liabilities
   
 46,263 
   
 24,603 
   
Changes in Certain Components of Working Capital:
           
     
Accounts Receivable, Net
   
 25,415 
   
 78,062 
     
Fuel, Materials and Supplies
   
 7,315 
   
 40,476 
     
Accounts Payable
   
 (75,799)
   
 (50,265)
     
Accrued Taxes, Net
   
 7,398 
   
 74,510 
     
Other Current Assets
   
 (3,368)
   
 2,924 
     
Other Current Liabilities
   
 39,541 
   
 24,264 
Net Cash Flows from Operating Activities
   
 433,753 
   
 624,642 
             
INVESTING ACTIVITIES
           
Construction Expenditures
   
 (212,006)
   
 (224,749)
Change in Advances to Affiliates, Net
   
 (189,054)
   
 (134,004)
Purchases of Investment Securities
   
 (744,131)
   
 (870,769)
Sales of Investment Securities
   
 698,567 
   
 825,689 
Acquisitions of Nuclear Fuel
   
 (12,545)
   
 (103,970)
Other Investing Activities
   
 29,714 
   
 35,583 
Net Cash Flows Used for Investing Activities
   
 (429,455)
   
 (472,220)
             
FINANCING ACTIVITIES
           
Issuance of Long-term Debt – Nonaffiliated
   
 128,228 
   
 76,414 
Change in Advances from Affiliates, Net
   
 - 
   
 (42,769)
Retirement of Long-term Debt – Nonaffiliated
   
 (78,062)
   
 (122,469)
Principal Payments for Capital Lease Obligations
   
 (4,929)
   
 (6,353)
Dividends Paid on Common Stock
   
 (50,000)
   
 (56,250)
Dividends Paid on Cumulative Preferred Stock
   
 - 
   
 (255)
Other Financing Activities
   
 212 
   
 53 
Net Cash Flows Used for Financing Activities
   
 (4,551)
   
 (151,629)
             
Net Increase (Decrease) in Cash and Cash Equivalents
   
 (253)
   
 793 
Cash and Cash Equivalents at Beginning of Period
   
 1,020 
   
 361 
Cash and Cash Equivalents at End of Period
 
$
 767 
 
$
 1,154 
             
SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 79,158 
 
$
 76,390 
Net Cash Paid (Received) for Income Taxes
   
 (29,089)
   
 (96,339)
Noncash Acquisitions Under Capital Leases
   
 4,993 
   
 2,492 
Construction Expenditures Included in Current Liabilities as of September 30,
   
 43,334 
   
 28,132 
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,
   
 42,957 
   
 46 
Noncash Increase in Long-term Debt Through the Fort Wayne Lease Settlement
   
 - 
   
 26,802 
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage
   
 28,057 
   
 - 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.

 
108

 

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 150.

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

 
109

 










OHIO POWER COMPANY CONSOLIDATED


 
110

 
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.

June 2012 – May 2015 Ohio ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP through May 2015.  The ESP allowed the continuation of the fuel adjustment clause and established a non-bypassable Distribution Investment Rider (DIR) effective September 2012 through May 2015 to recover, with certain caps, post-August 2010 distribution investment.  The DIR is capped at $86 million in 2012, $104 million in 2013, $124 million in 2014 and $52 million for the period January through May 2015, for a total of $366 million.  The ESP also maintained recovery of several previous ESP riders and required OPCo to contribute $2 million per year during the ESP to the Ohio Growth Fund.  In addition, the ESP approved a storm damage recovery mechanism which allowed OPCo to defer the majority of the incremental distribution operation and maintenance costs from 2012 storms.

Finally, the PUCO ordered OPCo to conduct an energy-only auction for 10% of the standard service offer (SSO) load with delivery beginning six months after the receipt of ESP and corporate separation orders and extending through December 2014.  The PUCO also ordered OPCo to conduct an energy-only auction for a total of 60% of the SSO load with delivery beginning June 2014 through May 2015.  In addition, the PUCO ordered OPCo to conduct an energy-only auction for the remaining 40% of the SSO load for delivery from January 2015 through May 2015.  Starting in June 2015, OPCo will conduct energy and capacity auctions for its entire SSO load.  In September 2012, OPCo and intervenors filed applications with the PUCO for rehearing.  Rehearing of this order is pending at the PUCO.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of 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.  Several parties, including OPCo, requested rehearing of the July 2012 PUCO order, which was upheld by the PUCO in October 2012.  In the August 2012 PUCO order which adopted and modified the new ESP, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR is intended to provide $508 million over the ESP period and will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the deferred capacity costs.  In August 2012, the Industrial Energy Users-Ohio (IEU) filed a claim before the Supreme Court of Ohio stating, among other things, that OPCo’s recovery of its capacity costs is illegal.  OPCo and the PUCO filed motions to dismiss IEU’s claim.  If OPCo is ultimately not permitted to fully collect its deferred capacity costs and ESP rates, including the RSR, it would reduce future net income and cash flows and impact financial condition.  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 third quarter of 2011 and the first nine months of 2011, OPCo lost approximately $74 million and $186 million, respectively, of gross margin.  This reduction in gross margin is partially offset by (a) collection of capacity revenues from CRES providers, (b) off-system sales, (c) deferral of unrecovered capacity costs and (d) Retail Stability Rider collections from retail distribution customers.  As of September 30, 2012, approximately 42% of OPCo’s load had switched to CRES providers and approximately 6% of OPCo’s load had formally initiated the switching process to a CRES provider for a total of 48%.

 
111

 
Securitization of Regulatory Assets

In August 2012, OPCo filed an application with the PUCO requesting securitization of the Deferred Asset Recovery Rider (DARR) balance.  As of September 30, 2012, OPCo’s DARR balance was $296 million, including $139 million of unrecognized equity carrying costs.  Currently, the DARR is being recovered through 2018 by a non-bypassable rider.

Significantly Excessive Earnings Test

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off in 2010 and a subsequent refund to customers during 2011.  In May 2011, the Industrial Energy Users-Ohio and the Ohio Energy Group 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 for a portion 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 one month after the PUCO issues an order on the 2010 SEET.  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.  Since the February 2012 PUCO order rejected the ESP modified stipulation, collection of the DIR terminated.  In August 2012, the PUCO approved a new DIR as filed in the ESP proceeding.  See the “2011 Ohio Distribution Base Rate Case” section of Note 2.

Special Rate Mechanism for Ormet

In October 2012, the PUCO issued an order approving a delayed payment plan for Ormet of its October and November 2012 power billings in equal monthly installment payments over the period January 2014 to May 2015 without interest.  In the event Ormet, a large industrial customer in Ohio, does not pay the deferred billings, the PUCO permitted OPCo to recover the unpaid balance up to $20 million in future rates.  To the extent unpaid deferred billings exceed $20 million, it will reduce future net income and cash flows.

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 150.  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 207 for additional discussion of relevant factors.

 
112

 
RESULTS OF OPERATIONS
                     
                           
KWh Sales/Degree Days
                     
 
Summary of KWh Energy Sales
                     
   
Three Months Ended
 
Nine Months Ended
   
September 30,
 
September 30,
 
2012
 
2011 
 
2012
 
2011 
   
(in millions of KWhs)
Retail:
                 
Residential
 
 4,198 
 
 4,166 
   
 11,079 
 
 11,758 
Commercial
 
 3,907 
 
 3,914 
   
 10,725 
 
 10,815 
Industrial
 
 4,463 
 
 4,840 
   
 13,982 
 
 14,195 
Miscellaneous
 
 27 
 
 28 
   
 85 
 
 91 
Total Retail (a)
 
 12,595 
 
 12,948 
   
 35,871 
 
 36,859 
                   
Wholesale
 
 4,173 
 
 3,743 
   
 9,477 
 
 9,424 
                   
Total KWhs
 
 16,768 
 
 16,691 
   
 45,348 
 
 46,283 
                     
(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
 
Nine Months Ended
   
September 30,
September 30,
   
2012 
 
2011 
 
2012 
 
2011 
   
(in degree days)
Actual - Heating (a)
 
 9 
   
 7 
   
 1,553 
   
 2,241 
Normal - Heating (b)
 
 8 
   
 8 
   
 2,121 
   
 2,109 
                         
Actual - Cooling (c)
 
 807 
   
 783 
   
 1,235 
   
 1,107 
Normal - Cooling (b)
 
 662 
   
 653 
   
 934 
   
 921 
                         
(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.

 
113

 

Third Quarter of 2012 Compared to Third Quarter of 2011
 
Reconciliation of Third Quarter of 2011 to Third Quarter of 2012
 
Net Income
 
(in millions)
 
       
Third Quarter of 2011
  $ 128  
         
Changes in Gross Margin:
       
Retail Margins
    (61 )
Off-system Sales
    (10 )
Transmission Revenues
    12  
Total Change in Gross Margin
    (59 )
         
Changes in Expenses and Other:
       
Other Operation and Maintenance
    20  
Asset Impairments and Other Related Charges
    90  
Depreciation and Amortization
    20  
Taxes Other Than Income Taxes
    (2 )
Carrying Costs Income
    (14 )
Other Income
    (4 )
Interest Expense
    3  
Total Change in Expenses and Other
    113  
         
Income Tax Expense
    (30 )
         
Third Quarter of 2012
  $ 152  

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 $61 million primarily due to the following:
   
·
An $80 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 $33 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 September 2011.
   
·
A $10 million net decrease in regulated revenue due to the elimination of POLR charges, effective June 2011, partially offset by the third quarter 2011 provision for refund of POLR charges.  The refund provision was recorded as a result of the October 2011 PUCO remand order.
   
These decreases were partially offset by:
   
·
A $44 million increase in revenues associated with the Retail Stability Rider, Deferred Asset Recovery Rider and Distribution Investment Recovery Rider.  The majority of these increases have corresponding increases in other expense items below.
   
·
A $13 million decrease in recoverable PJM expenses.
 
·
Margins from Off-system Sales decreased $10 million primarily due to lower market prices, reduced physical sales volumes and lower trading and marketing margins, partially offset by higher PJM capacity revenues.
 
·
Transmission Revenues increased $12 million primarily due to increased transmission revenues from 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.

 
114

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

 
·
Other Operation and Maintenance expenses decreased $20 million primarily due to the following:
   
·
A $9 million decrease in plant maintenance expenses at various plants.
   
·
A $9 million decrease due to the third quarter 2011 write-off of allocated Front-End Engineering and Design (FEED) study costs related to the Mountaineer Carbon Capture Project.
   
·
A $3 million decrease due to the deferral of capacity-related costs as a result of the PUCO's July 2012 approval of OPCo's capacity rate proceeding.
   
These decreases were partially offset by:
   
·
A $6 million increase related to the third quarter 2012 recording of an obligation to contribute to Ohio Growth Fund as approved by the PUCO in August 2012.
 
·
Asset Impairments and Other Related Charges decreased $90 million due to the third quarter 2011 plant impairments of Sporn Unit 5 and the FGD project at Muskingum River Unit 5.
 
·
Depreciation and Amortization expenses decreased $20 million primarily due to the following:
   
·
A $21 million decrease due to the amortization of debt and equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances.  The equity amortization was offset by amounts recognized in Carrying Costs Income as discussed below.
   
·
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 $9 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of OPCo's capacity rate proceeding.
   
·
A $3 million decrease in depreciation due to the third quarter 2011 plant impairment of Sporn Unit 5.
   
These decreases were partially offset by:
   
·
A $17 million increase due to shortened depreciable lives for certain generating plants effective December 2011.
   
·
A $4 million increase in amortization of the Deferred Asset Recovery Rider assets as approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.  This increase in amortization is offset within Gross Margin.
 
·
Carrying Costs Income decreased $14 million primarily due to the recognition of equity carrying costs income on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances.  The equity carrying costs income was offset by amounts in Depreciation and Amortization discussed above.
 
·
Other Income decreased $4 million primarily due to interest income recorded in the third quarter of 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
 
·
Interest Expense decreased $3 million as a result of a net increase in capitalized interest.
 
·
Income Tax Expense increased $30 million primarily due to an increase in pretax book income and state income tax adjustments related to prior year tax returns.

 
115

 

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011
 
Reconciliation of Nine Months Ended September 30, 2011 to Nine Months Ended September 30, 2012
 
Net Income
 
(in millions)
 
       
Nine Months Ended September 30, 2011
  $ 437  
         
Changes in Gross Margin:
       
Retail Margins
    (247 )
Off-system Sales
    8  
Transmission Revenues
    29  
Other Revenues
    2  
Total Change in Gross Margin
    (208 )
         
Changes in Expenses and Other:
       
Other Operation and Maintenance
    99  
Asset Impairments and Other Related Charges
    90  
Depreciation and Amortization
    11  
Taxes Other Than Income Taxes
    (5 )
Carrying Costs Income
    (28 )
Other Income
    (4 )
Interest Expense
    9  
Total Change in Expenses and Other
    172  
         
Income Tax Expense
    3  
         
Nine Months Ended September 30, 2012
  $ 404  

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 $247 million primarily due to the following:
   
·
A $204 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 $121 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 September 2011.
   
·
An $81 million net decrease in regulated revenue due to the elimination of POLR charges, effective June 2011, partially offset by the third quarter 2011 provision for refund of POLR charges.  The refund provision was recorded as a result of the October 2011 PUCO remand order.
   
·
A $14 million decrease in weather-related usage primarily due to a 31% decrease in heating degree days.
   
These decreases were partially offset by:
   
·
A $94 million increase in revenues associated with the Retail Stability Rider, Deferred Asset Recovery Rider and Distribution Investment Recovery Rider.  The majority of these increases have corresponding increases in other expense items below.
   
·
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.
   
·
A $30 million decrease in recoverable PJM expenses.
   
·
A $14 million increase due to higher sales to Buckeye Power, Inc. to provide backup energy under the Cardinal Station Agreement.
 
·
Margins from Off-system Sales increased $8 million primarily due to higher PJM capacity revenues, partially offset by lower market prices, reduced physical sales volumes and lower trading and marketing margins.
 
 
116

 
 
·
Transmission Revenues increased $29 million primarily due to increased transmission revenues from 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.

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

 
·
Other Operation and Maintenance expenses decreased $99 million primarily due to the following:
   
·
A $49 million decrease in plant maintenance expenses at various plants.
   
·
A $30 million net decrease related to the 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 and the PUCO's August 2012 approval of the June 2012-May 2015 ESP.
   
·
A $9 million decrease due to the third quarter 2011 write-off of allocated FEED study costs related to the Mountaineer Carbon Capture Project.
   
·
A $7 million decrease in employee-related expenses.
   
·
A $3 million decrease as a result of a legal proceeding recorded in second quarter 2011.
   
·
A $3 million decrease due to the deferral of capacity-related costs as a result of the PUCO's July 2012 approval of OPCo's capacity rate proceeding.
   
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 $4 million increase due to expenses related to the 2012 sustainable cost reductions.
 
·
Asset Impairments and Other Related Charges decreased $90 million due to the third quarter 2011 plant impairments of Sporn Unit 5 and the FGD project at Muskingum River Unit 5.
 
·
Depreciation and Amortization expenses decreased $11 million primarily due to the following:
   
·
A $29 million decrease due to an amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
   
·
A $21 million decrease due to the amortization of debt and equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances.  The equity amortization was offset by amounts recognized in Carrying Costs Income as discussed below.
   
·
A $13 million decrease in depreciation due to the third quarter 2011 plant impairment of Sporn Unit 5.
   
·
A $9 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of OPCo's capacity rate proceeding.
   
These decreases were partially offset by:
   
·
A $49 million increase due to shortened depreciable lives for certain generating plants effective December 2011.
   
·
A $9 million increase in amortization of the Deferred Asset Recovery Rider assets as approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.  This increase in amortization is offset within Gross Margin.
 
·
Taxes Other Than Income Taxes increased $5 million primarily due to increased capital investments and increased tax rates.
 
·
Carrying Costs Income decreased $28 million primarily due to the following:
   
·
An $11 million decrease due to the recognition of equity carrying costs income on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances.  The equity carrying costs income was offset by amounts in Depreciation and Amortization discussed above.
   
·
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.
   
·
A $5 million decrease due to line extension carrying charges recorded in 2011.
 
·
Interest Expense decreased $9 million as a result of a net increase in capitalized interest and the reversal of interest accruals related to federal tax reserve positions.
 
·
Income Tax Expense decreased $3 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 and state and federal income tax adjustments related to prior year tax returns.

 
117

 
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 207 for a discussion of accounting pronouncements.

 
118

 

OHIO POWER COMPANY CONSOLIDATED
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
For the Three and Nine Months Ended September 30, 2012 and 2011
 
(in thousands)
 
(Unaudited)
 
   
   
Three Months Ended
   
Nine Months Ended
 
   
2012
   
2011
   
2012
   
2011
 
REVENUES
                       
Electric Generation, Transmission and Distribution
  $ 1,114,339     $ 1,241,423     $ 3,084,657     $ 3,413,128  
Sales to AEP Affiliates
    229,879       285,010       584,197       773,169  
Other Revenues - Affiliated
    10,207       9,066       27,297       20,591  
Other Revenues - Nonaffiliated
    5,391       4,732       14,638       13,091  
TOTAL REVENUES
    1,359,816       1,540,231       3,710,789       4,219,979  
                                 
EXPENSES
                               
Fuel and Other Consumables Used for Electric Generation
    426,989       479,938       1,095,276       1,228,067  
Purchased Electricity for Resale
    46,146       65,834       156,384       203,231  
Purchased Electricity from AEP Affiliates
    109,453       157,776       279,954       402,121  
Other Operation
    189,566       202,272       481,994       532,224  
Maintenance
    73,024       80,587       227,643       276,029  
Asset Impairments and Other Related Charges
    -       89,824       -       89,824  
Depreciation and Amortization
    130,026       149,626       401,465       412,736  
Taxes Other Than Income Taxes
    105,503       103,921       309,341       304,364  
TOTAL EXPENSES
    1,080,707       1,329,778       2,952,057       3,448,596  
                                 
OPERATING INCOME
    279,109       210,453       758,732       771,383  
                                 
Other Income (Expense):
                               
Interest Income
    425       4,167       1,868       5,062  
Carrying Costs Income
    7,132       21,586       14,401       42,164  
Allowance for Equity Funds Used During Construction
    998       1,413       3,036       4,124  
Interest Expense
    (53,576 )     (56,677 )     (160,984 )     (170,328 )
                                 
INCOME BEFORE INCOME TAX EXPENSE
    234,088       180,942       617,053       652,405  
                                 
Income Tax Expense
    82,578       52,603       213,290       215,902  
                                 
NET INCOME
    151,510       128,339       403,763       436,503  
                                 
Preferred Stock Dividend Requirements Including
                               
Capital Stock Expense
    -       208       -       624  
                                 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
  $ 151,510     $ 128,131     $ 403,763     $ 435,879  
                                 
The common stock of OPCo is wholly-owned by AEP.
                               
                                 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 

 
119

 
 
OHIO POWER COMPANY CONSOLIDATED
 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 
For the Three and Nine Months Ended September 30, 2012 and 2011
 
(in thousands)
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
2012
 
2011
 
2012
 
2011
 
Net Income
  $ 151,510   $ 128,339   $ 403,763   $ 436,503  
                           
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                         
Cash Flow Hedges, Net of Tax of $956 and $648 for the Three Months Ended
                         
September 30, 2012 and 2011, Respectively, and $111 and $368 for the Nine
                         
Months Ended September 30, 2012 and 2011, Respectively
    1,776     (1,204 )   205     (683 )
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,745
                         
and $1,577 for the Three Months Ended September 30, 2012 and 2011,
                         
Respectively, and $5,234 and $4,421 for the Nine Months Ended
                         
September 30, 2012 and 2011, Respectively
    3,240     2,929     9,721     8,210  
                           
TOTAL OTHER COMPREHENSIVE INCOME
    5,016     1,725     9,926     7,527  
                           
TOTAL COMPREHENSIVE INCOME
  $ 156,526   $ 130,064   $ 413,689   $ 444,030  
                           
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 

 
120

 
 
OHIO POWER COMPANY CONSOLIDATED
 
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
 
COMMON SHAREHOLDER'S EQUITY
 
For the Nine Months Ended September 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
                    (487,500 )             (487,500 )
Preferred Stock Dividends
                    (549 )             (549 )
Capital Stock Expense
            75       (75 )             -  
Subtotal – Common Shareholder's Equity
                                    4,166,590  
                                         
Net Income
                    436,503               436,503  
Other Comprehensive Income
                            7,527       7,527  
TOTAL COMMON SHAREHOLDER'S
                                       
EQUITY –  SEPTEMBER 30, 2011
  $ 321,201     $ 1,745,066     $ 2,716,981     $ (172,628 )   $ 4,610,620  
                                         
TOTAL COMMON SHAREHOLDER'S
                                       
EQUITY – DECEMBER 31, 2011
  $ 321,201     $ 1,744,099     $ 2,582,600     $ (197,722 )   $ 4,450,178  
                                         
Common Stock Dividends
                    (225,000 )             (225,000 )
Subtotal – Common Shareholder's Equity
                                    4,225,178  
                                         
Net Income
                    403,763               403,763  
Other Comprehensive Income
                            9,926       9,926  
TOTAL COMMON SHAREHOLDER'S
                                       
EQUITY –  SEPTEMBER 30, 2012
  $ 321,201     $ 1,744,099     $ 2,761,363     $ (187,796 )   $ 4,638,867  
                                         
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 

 
121

 

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)
 
   
2012 
 
2011 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
 1,930 
 
$
 2,095 
Advances to Affiliates
   
 124,606 
   
 219,458 
Accounts Receivable:
           
 
Customers
   
 103,211 
   
 146,432 
 
Affiliated Companies
   
 150,978 
   
 162,830 
 
Accrued Unbilled Revenues
   
 51,967 
   
 19,012 
 
Miscellaneous
   
 6,391 
   
 16,994 
 
Allowance for Uncollectible Accounts
   
 (26)
   
 (3,563)
   
Total Accounts Receivable
   
 312,521 
   
 341,705 
Fuel
   
 325,330 
   
 262,886 
Materials and Supplies
   
 187,899 
   
 201,325 
Risk Management Assets
   
 44,704 
   
 54,293 
Accrued Tax Benefits
   
 1,512 
   
 11,975 
Prepayments and Other Current Assets
   
 33,276 
   
 41,560 
TOTAL CURRENT ASSETS
   
 1,031,778 
   
 1,135,297 
             
PROPERTY, PLANT AND EQUIPMENT
           
Electric:
           
 
Generation
   
 9,608,241 
   
 9,502,614 
 
Transmission
   
 1,986,600 
   
 1,948,329 
 
Distribution
   
 3,690,824 
   
 3,545,574 
Other Property, Plant and Equipment
   
 585,349 
   
 546,642 
Construction Work in Progress
   
 318,092 
   
 354,465 
Total Property, Plant and Equipment
   
 16,189,106 
   
 15,897,624 
Accumulated Depreciation and Amortization
   
 5,894,263 
   
 5,742,561 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
   
 10,294,843 
   
 10,155,063 
             
OTHER NONCURRENT ASSETS
           
Regulatory Assets
   
 1,455,396 
   
 1,370,504 
Long-term Risk Management Assets
   
 54,327 
   
 53,614 
Deferred Charges and Other Noncurrent Assets
   
 140,166 
   
 309,775 
TOTAL OTHER NONCURRENT ASSETS
   
 1,649,889 
   
 1,733,893 
             
TOTAL ASSETS
 
$
 12,976,510 
 
$
 13,024,253 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 
 
122

 
OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
September 30, 2012 and December 31, 2011
(Unaudited)
 
   
2012 
 
2011 
     
(in thousands)
CURRENT LIABILITIES
           
Accounts Payable:
           
 
General
 
$
 233,017 
 
$
 293,730 
 
Affiliated Companies
   
 101,268 
   
 183,898 
Long-term Debt Due Within One Year – Nonaffiliated
   
 856,000 
   
 244,500 
Risk Management Liabilities
   
 26,658 
   
 36,561 
Accrued Taxes
   
 249,301 
   
 450,570 
Accrued Interest
   
 66,973 
   
 66,441 
Other Current Liabilities
   
 267,814 
   
 238,275 
TOTAL CURRENT LIABILITIES
   
 1,801,031 
   
 1,513,975 
             
NONCURRENT LIABILITIES
           
Long-term Debt – Nonaffiliated
   
 2,804,242 
   
 3,609,648 
Long-term Debt – Affiliated
   
 200,000 
   
 200,000 
Long-term Risk Management Liabilities
   
 29,513 
   
 17,890 
Deferred Income Taxes
   
 2,398,292 
   
 2,245,380 
Regulatory Liabilities and Deferred Investment Tax Credits
   
 475,437 
   
 301,124 
Employee Benefits and Pension Obligations
   
 299,560 
   
 335,029 
Deferred Credits and Other Noncurrent Liabilities
   
 329,568 
   
 351,029 
TOTAL NONCURRENT LIABILITIES
   
 6,536,612 
   
 7,060,100 
             
TOTAL LIABILITIES
   
 8,337,643 
   
 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
   
 2,761,363 
   
 2,582,600 
Accumulated Other Comprehensive Income (Loss)
   
 (187,796)
   
 (197,722)
TOTAL COMMON SHAREHOLDER’S EQUITY
   
 4,638,867 
   
 4,450,178 
             
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
 12,976,510 
 
$
 13,024,253 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.

 
123

 

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2012 and 2011
(in thousands)
(Unaudited)
 
   
2012 
 
2011 
OPERATING ACTIVITIES
           
Net Income
 
$
 403,763 
 
$
 436,503 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
           
   
Depreciation and Amortization
   
 401,465 
   
 412,736 
   
Deferred Income Taxes
   
 126,009 
   
 117,803 
   
Asset Impairments and Other Related Charges
   
 - 
   
 89,824 
   
Carrying Costs Income
   
 (14,401)
   
 (42,164)
   
Allowance for Equity Funds Used During Construction
   
 (3,036)
   
 (4,124)
   
Mark-to-Market of Risk Management Contracts
   
 12,420 
   
 14,548 
   
Property Taxes
   
 164,496 
   
 160,466 
   
Fuel Over/Under-Recovery, Net
   
 4,766 
   
 (41,989)
   
Change in Other Noncurrent Assets
   
 (77,310)
   
 (60,179)
   
Change in Other Noncurrent Liabilities
   
 (11,019)
   
 19,110 
   
Changes in Certain Components of Working Capital:
           
     
Accounts Receivable, Net
   
 29,255 
   
 126,873 
     
Fuel, Materials and Supplies
   
 (46,712)
   
 129,232 
     
Accounts Payable
   
 (135,419)
   
 (77,427)
     
Accrued Taxes, Net
   
 (161,613)
   
 (197,378)
     
Other Current Assets
   
 2,599 
   
 12,711 
     
Other Current Liabilities
   
 (3,639)
   
 (28,093)
Net Cash Flows from Operating Activities
   
 691,624 
   
 1,068,452 
             
INVESTING ACTIVITIES
           
Construction Expenditures
   
 (374,417)
   
 (299,854)
Change in Advances to Affiliates, Net
   
 94,852 
   
 (225,426)
Acquisitions of Assets
   
 (116)
   
 (1,734)
Proceeds from Sales of Assets
   
 6,226 
   
 47,075 
Other Investing Activities
   
 8,642 
   
 26,013 
Net Cash Flows Used for Investing Activities
   
 (264,813)
   
 (453,926)
             
FINANCING ACTIVITIES
           
Issuance of Long-term Debt – Nonaffiliated
   
 - 
   
 49,757 
Retirement of Long-term Debt – Nonaffiliated
   
 (194,500)
   
 (165,000)
Retirement of Cumulative Preferred Stock
   
 - 
   
 (2)
Principal Payments for Capital Lease Obligations
   
 (7,678)
   
 (8,956)
Dividends Paid on Common Stock
   
 (225,000)
   
 (487,500)
Dividends Paid on Cumulative Preferred Stock
   
 - 
   
 (549)
Other Financing Activities
   
 202 
   
 18 
Net Cash Flows Used for Financing Activities
   
 (426,976)
   
 (612,232)
             
Net Increase (Decrease) in Cash and Cash Equivalents
   
 (165)
   
 2,294 
Cash and Cash Equivalents at Beginning of Period
   
 2,095 
   
 949 
Cash and Cash Equivalents at End of Period
 
$
 1,930 
 
$
 3,243 
             
SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 157,944 
 
$
 165,600 
Net Cash Paid for Income Taxes
   
 33,400 
   
 103,310 
Noncash Acquisitions Under Capital Leases
   
 5,658 
   
 2,198 
Government Grants Included in Accounts Receivable as of September 30,
   
 585 
   
 1,539 
Construction Expenditures Included in Current Liabilities as of September 30,
   
 56,357 
   
 46,138 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.

 
124

 

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 150.

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

 
125

 














PUBLIC SERVICE COMPANY OF OKLAHOMA


 
126

 
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 150.  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 207 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
                     
                           
KWh Sales/Degree Days
                     
 
Summary of KWh Energy Sales
                     
   
Three Months Ended
 
Nine Months Ended
   
September 30,
 
September 30,
 
2012
 
2011 
 
2012
 
2011 
   
(in millions of KWhs)
Retail:
                 
Residential
 
 2,332 
 
 2,423 
   
 5,211 
 
 5,500 
Commercial
 
 1,518 
 
 1,476 
   
 3,992 
 
 3,996 
Industrial
 
 1,346 
 
 1,378 
   
 3,837 
 
 3,743 
Miscellaneous
 
 383 
 
 390 
   
 1,025 
 
 1,007 
Total Retail (a)
 
 5,579 
 
 5,667 
   
 14,065 
 
 14,246 
                   
Wholesale
 
 334 
 
 314 
   
 1,273 
 
 866 
                   
Total KWhs
 
 5,913 
 
 5,981 
   
 15,338 
 
 15,112 
                     
(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
 
Nine Months Ended
   
September 30,
September 30,
   
2012 
 
2011 
 
2012 
 
2011 
   
(in degree days)
Actual - Heating (a)
 
 - 
   
 - 
   
 676 
   
 1,276 
Normal - Heating (b)
 
 2 
   
 2 
   
 1,109 
   
 1,102 
                         
Actual - Cooling (c)
 
 1,622 
   
 1,749 
   
 2,557 
   
 2,694 
Normal - Cooling (b)
 
 1,398 
   
 1,391 
   
 2,046 
   
 2,028 
                         
(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.

 
127

 

Third Quarter of 2012 Compared to Third Quarter of 2011
 
Reconciliation of Third Quarter of 2011 to Third Quarter of 2012
 
Net Income
 
(in millions)
 
       
Third Quarter of 2011
  $ 57  
         
Changes in Gross Margin:
       
Retail Margins (a)
    (1 )
Off-system Sales
    (1 )
Other Revenues
    (1 )
Total Change in Gross Margin
    (3 )
         
Changes in Expenses and Other:
       
Other Operation and Maintenance
    5  
Taxes Other Than Income Taxes
    1  
Total Change in Expenses and Other
    6  
         
Income Tax Expense
    (2 )
         
Third Quarter of 2012
  $ 58  
         
(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 $1 million primarily due to the following:
   
·
A $5 million decrease in weather-related usage primarily due to a 7% decrease in cooling degree days.
   
This decrease was partially offset by:
   
·
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 below.

Expenses and Other changed between years as follows:

 
·
Other Operation and Maintenance expenses decreased $5 million primarily due to the following:
   
·
A $5 million decrease in generation plant maintenance expenses.
   
·
A $3 million decrease in distribution maintenance expenses primarily due to decreased vegetation management expenses.
   
·
A $2 million decrease in demand side management programs.
   
These decreases were partially offset by:
   
·
A $5 million increase in transmission expenses primarily due to increased SPP transmission services.

 
128

 
 
Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011
 
Reconciliation of Nine Months Ended September 30, 2011 to Nine Months Ended September 30, 2012
Net Income
(in millions)
         
Nine Months Ended September 30, 2011
 
$
 104 
 
         
Changes in Gross Margin:
       
Retail Margins (a)
   
 8 
 
Off-system Sales
   
 (1)
 
Transmission Revenues
   
 (2)
 
Other Revenues
   
 1 
 
Total Change in Gross Margin
   
 6 
 
         
Changes in Expenses and Other:
       
Other Operation and Maintenance
   
 (4)
 
Depreciation and Amortization
   
 1 
 
Interest Expense
   
 2 
 
Total Change in Expenses and Other
   
 (1)
 
         
Income Tax Expense
   
 (3)
 
         
Nine Months Ended September 30, 2012
 
$
 106 
 
         
(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 $8 million primarily due to the following:
   
·
An $11 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.
   
·
A $9 million increase primarily due to higher commercial and residential non-weather related usage.
   
These increases were partially offset by:
   
·
A $13 million decrease in weather-related usage primarily due to a 47% decrease in heating degree days and a 5% decrease in cooling degree days.

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

 
·
Other Operation and Maintenance expenses increased $4 million primarily due to the following:
   
·
A $12 million increase in transmission expenses primarily due to increased SPP transmission services.
   
This increase was partially offset by:
   
·
A $7 million decrease in general and administrative expenses.
   
·
A $2 million decrease in distribution expenses primarily due to decreased overhead line expense.
 
·
Income Tax Expense increased $3 million primarily due to an increase in pretax book income and state income taxes.

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 207 for a discussion of accounting pronouncements.

 
129

 

PUBLIC SERVICE COMPANY OF OKLAHOMA
 
CONDENSED STATEMENTS OF INCOME
 
For the Three and Nine Months Ended September 30, 2012 and 2011
 
(in thousands)
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
2012
   
2011
   
2012
   
2011
 
REVENUES
                       
Electric Generation, Transmission and Distribution
  $ 364,851     $ 454,802     $ 968,683     $ 1,061,417  
Sales to AEP Affiliates
    6,865       2,115       19,377       10,696  
Other Revenues
    1,156       669       2,654       2,064  
TOTAL REVENUES
    372,872       457,586       990,714       1,074,177  
                                 
EXPENSES
                               
Fuel and Other Consumables Used for Electric Generation
    65,195       168,230       281,746       360,774  
Purchased Electricity for Resale
    75,719       42,455       145,983       129,652  
Purchased Electricity from AEP Affiliates
    5,870       17,477       16,328       43,199  
Other Operation
    58,975       58,225       154,834       151,365  
Maintenance
    25,685       31,892       78,863       77,765  
Depreciation and Amortization
    24,433       24,802       71,356       72,761  
Taxes Other Than Income Taxes
    10,799       11,499       32,619       32,589  
TOTAL EXPENSES
    266,676       354,580       781,729       868,105  
                                 
OPERATING INCOME
    106,196       103,006       208,985       206,072  
                                 
Other Income (Expense):
                               
Interest Income
    171       164       1,203       244  
Carrying Costs Income
    418       810       1,560       3,333  
Allowance for Equity Funds Used During Construction
    408       189       1,298       839  
Interest Expense
    (13,735 )     (13,831 )     (42,212 )     (44,027 )
                                 
INCOME BEFORE INCOME TAX EXPENSE
    93,458       90,338       170,834       166,461  
                                 
Income Tax Expense
    35,355       32,989       64,872       62,163  
                                 
NET INCOME
    58,103       57,349       105,962       104,298  
                                 
Preferred Stock Dividend Requirements
    -       49       -       147  
                                 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
  $ 58,103     $ 57,300     $ 105,962     $ 104,151  
                                 
The common stock of PSO is wholly-owned by AEP.
                               
                                 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 

 
130

 


PUBLIC SERVICE COMPANY OF OKLAHOMA
 
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 
For the Three and Nine Months Ended September 30, 2012 and 2011
 
(in thousands)
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
2012
 
2011
 
2012
 
2011
 
Net Income
  $ 58,103   $ 57,349   $ 105,962   $ 104,298  
                           
OTHER COMPREHENSIVE LOSS, NET OF TAXES
                         
Cash Flow Hedges, Net of Tax of $28 and $233 for the Three Months Ended
                         
September 30, 2012 and 2011, Respectively, and $250 and $640 for the Nine
                         
Months Ended September 30, 2012 and 2011, Respectively
    (53 )   (432 )   (465 )   (1,188 )
                           
TOTAL COMPREHENSIVE INCOME
  $ 58,050   $ 56,917   $ 105,497   $ 103,110  
                           
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 

 
131

 


PUBLIC SERVICE COMPANY OF OKLAHOMA
 
CONDENSED STATEMENTS OF CHANGES IN
 
COMMON SHAREHOLDER'S EQUITY
 
For the Nine Months Ended September 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
                    (52,500 )             (52,500 )
Preferred Stock Dividends
                    (147 )             (147 )
Subtotal – Common Shareholder's Equity
                                    789,825  
                                         
Net Income
                    104,298               104,298  
Other Comprehensive Loss
                            (1,188 )     (1,188 )
TOTAL COMMON SHAREHOLDER'S
                                       
EQUITY – SEPTEMBER 30, 2011
  $ 157,230     $ 364,307     $ 364,092     $ 7,306     $ 892,935  
                                         
TOTAL COMMON SHAREHOLDER'S
                                       
EQUITY – DECEMBER 31, 2011
  $ 157,230     $ 364,037     $ 364,389     $ 7,149     $ 892,805  
                                         
Common Stock Dividends
                    (60,000 )             (60,000 )
Subtotal – Common Shareholder's Equity
                                    832,805  
                                         
Net Income
                    105,962               105,962  
Other Comprehensive Loss
                            (465 )     (465 )
TOTAL COMMON SHAREHOLDER'S
                                       
EQUITY – SEPTEMBER 30, 2012
  $ 157,230     $ 364,037     $ 410,351     $ 6,684     $ 938,302  
                                         
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 

 
132

 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)
 
   
2012 
 
2011 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
 1,022 
 
$
 1,413 
Advances to Affiliates
   
 107,459 
   
 39,876 
Accounts Receivable:
           
 
Customers
   
 30,220 
   
 39,977 
 
Affiliated Companies
   
 27,952 
   
 23,079 
 
Miscellaneous
   
 3,688 
   
 8,993 
 
Allowance for Uncollectible Accounts
   
 (1,179)
   
 (777)
   
Total Accounts Receivable
   
 60,681 
   
 71,272 
Fuel
   
 21,820 
   
 20,854 
Materials and Supplies
   
 51,701 
   
 50,347 
Risk Management Assets
   
 545 
   
 565 
Deferred Income Tax Benefits
   
 9,925 
   
 7,013 
Accrued Tax Benefits
   
 7,714 
   
 6,733 
Regulatory Asset for Under-Recovered Fuel Costs
   
 - 
   
 4,313 
Prepayments and Other Current Assets
   
 8,030 
   
 6,440 
TOTAL CURRENT ASSETS
   
 268,897 
   
 208,826 
             
PROPERTY, PLANT AND EQUIPMENT
           
Electric:
           
 
Generation
   
 1,335,087 
   
 1,317,948 
 
Transmission
   
 702,696 
   
 692,644 
 
Distribution
   
 1,836,835 
   
 1,762,110 
Other Property, Plant and Equipment
   
 228,234 
   
 214,626 
Construction Work in Progress
   
 69,842 
   
 70,371 
Total Property, Plant and Equipment
   
 4,172,694 
   
 4,057,699 
Accumulated Depreciation and Amortization
   
 1,290,823 
   
 1,266,816 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
   
 2,881,871 
   
 2,790,883 
             
OTHER NONCURRENT ASSETS
           
Regulatory Assets
   
 241,984 
   
 266,545 
Long-term Risk Management Assets
   
 124 
   
 314 
Deferred Charges and Other Noncurrent Assets
   
 18,824 
   
 13,536 
TOTAL OTHER NONCURRENT ASSETS
   
 260,932 
   
 280,395 
             
TOTAL ASSETS
 
$
 3,411,700 
 
$
 3,280,104 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 
 
133

 
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
September 30, 2012 and December 31, 2011
(Unaudited)
             
   
2012 
 
2011 
     
(in thousands)
CURRENT LIABILITIES
           
Accounts Payable:
           
 
General
 
$
 83,313 
 
$
 76,607 
 
Affiliated Companies
   
 22,996 
   
 45,029 
Long-term Debt Due Within One Year – Nonaffiliated
   
 761 
   
 311 
Risk Management Liabilities
   
 5,071 
   
 1,280 
Customer Deposits
   
 46,577 
   
 47,493 
Accrued Taxes
   
 59,612 
   
 21,660 
Accrued Interest
   
 15,350 
   
 12,637 
Regulatory Liability for Over-Recovered Fuel Costs
   
 35,927 
   
 - 
Other Current Liabilities
   
 39,434 
   
 43,586 
TOTAL CURRENT LIABILITIES
   
 309,041 
   
 248,603 
             
NONCURRENT LIABILITIES
           
Long-term Debt – Nonaffiliated
   
 949,123 
   
 947,053 
Long-term Risk Management Liabilities
   
 1,051 
   
 1,330 
Deferred Income Taxes
   
 754,313 
   
 726,463 
Regulatory Liabilities and Deferred Investment Tax Credits
   
 343,276 
   
 334,812 
Employee Benefits and Pension Obligations
   
 74,551 
   
 84,548 
Deferred Credits and Other Noncurrent Liabilities
   
 42,043 
   
 44,490 
TOTAL NONCURRENT LIABILITIES
   
 2,164,357 
   
 2,138,696 
             
TOTAL LIABILITIES
   
 2,473,398 
   
 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
   
 410,351 
   
 364,389 
Accumulated Other Comprehensive Income (Loss)
   
 6,684 
   
 7,149 
TOTAL COMMON SHAREHOLDER’S EQUITY
   
 938,302 
   
 892,805 
             
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
 3,411,700 
 
$
 3,280,104 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.

 
134

 

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2012 and 2011
(in thousands)
(Unaudited)
 
   
2012 
 
2011 
OPERATING ACTIVITIES
           
Net Income
 
$
 105,962 
 
$
 104,298 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating
           
 
Activities:
           
   
Depreciation and Amortization
   
 71,356 
   
 72,761 
   
Deferred Income Taxes
   
 22,524 
   
 45,927 
   
Carrying Costs Income
   
 (1,560)
   
 (3,333)
   
Allowance for Equity Funds Used During Construction
   
 (1,298)
   
 (839)
   
Mark-to-Market of Risk Management Contracts
   
 3,868 
   
 (2,226)
   
Fuel Over/Under-Recovery, Net
   
 40,240 
   
 4,389 
   
Change in Other Noncurrent Assets
   
 1,196 
   
 4,326 
   
Change in Other Noncurrent Liabilities
   
 (1,325)
   
 22,794 
   
Changes in Certain Components of Working Capital:
           
     
Accounts Receivable, Net
   
 10,684 
   
 53,995 
     
Fuel, Materials and Supplies
   
 (2,320)
   
 468 
     
Accounts Payable
   
 (11,632)
   
 3,506 
     
Accrued Taxes, Net
   
 43,313 
   
 63,993 
     
Other Current Assets
   
 (1,864)
   
 (3,839)
     
Other Current Liabilities
   
 (1,275)
   
 11,593 
Net Cash Flows from Operating Activities
   
 277,869 
   
 377,813 
             
INVESTING ACTIVITIES
           
Construction Expenditures
   
 (151,603)
   
 (97,038)
Change in Advances to Affiliates, Net
   
 (67,583)
   
 (105,116)
Other Investing Activities
   
 1,107 
   
 782 
Net Cash Flows Used for Investing Activities
   
 (218,079)
   
 (201,372)
             
FINANCING ACTIVITIES
           
Issuance of Long-term Debt – Nonaffiliated
   
 2,395 
   
 247,481 
Change in Advances from Affiliates, Net
   
 - 
   
 (91,382)
Retirement of Long-term Debt – Nonaffiliated
   
 (130)
   
 (275,000)
Principal Payments for Capital Lease Obligations
   
 (2,585)
   
 (3,103)
Dividends Paid on Common Stock
   
 (60,000)
   
 (52,500)
Dividends Paid on Cumulative Preferred Stock
   
 - 
   
 (147)
Other Financing Activities
   
 139 
   
 13 
Net Cash Flows Used for Financing Activities
   
 (60,181)
   
 (174,638)
             
Net Increase (Decrease) in Cash and Cash Equivalents
   
 (391)
   
 1,803 
Cash and Cash Equivalents at Beginning of Period
   
 1,413 
   
 470 
Cash and Cash Equivalents at End of Period
 
$
 1,022 
 
$
 2,273 
             
SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 36,681 
 
$
 23,397 
Net Cash Paid (Received) for Income Taxes
   
 17,988 
   
 (26,536)
Noncash Acquisitions Under Capital Leases
   
 979 
   
 634 
Construction Expenditures Included in Current Liabilities as of September 30,
   
 23,872 
   
 13,400 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.

 
135

 

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 150.

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

 
136

 










SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

 
137

 
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 included a return on and of the Texas jurisdictional share of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operations and maintenance costs.  In September 2012, an Administrative Law Judge issued an order that granted the establishment of SWEPCo’s existing rates as temporary rates beginning in late January 2013, subject to true-up to the final PUCT-approved rates.  A decision from the PUCT is expected in the second quarter of 2013.  See “2012 Texas Base Rate Case” section of Note 2.

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 150.  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 207 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
                     
                           
KWh Sales/Degree Days
                     
 
Summary of KWh Energy Sales
                     
   
Three Months Ended
 
Nine Months Ended
   
September 30,
 
September 30,
 
2012
 
2011 
 
2012
 
2011 
   
(in millions of KWhs)
Retail:
                 
Residential
 
 2,120 
 
 2,372 
   
 5,072 
 
 5,621 
Commercial
 
 1,764 
 
 1,831 
   
 4,718 
 
 4,861 
Industrial
 
 1,448 
 
 1,372 
   
 4,279 
 
 4,049 
Miscellaneous
 
 20 
 
 19 
   
 60 
 
 61 
Total Retail (a)
 
 5,352 
 
 5,594 
   
 14,129 
 
 14,592 
                   
Wholesale
 
 2,108 
 
 2,410 
   
 5,987 
 
 6,074 
                   
Total KWhs
 
 7,460 
 
 8,004 
   
 20,116 
 
 20,666 
                     
(a) Represents energy delivered to distribution customers.

 
138

 
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
 
Nine Months Ended
   
September 30,
September 30,
   
2012 
 
2011 
 
2012 
 
2011 
   
(in degree days)
Actual - Heating (a)
 
 - 
   
 - 
   
 427 
   
 866 
Normal - Heating (b)
 
 1 
   
 1 
   
 774 
   
 774 
                         
Actual - Cooling (c)
 
 1,457 
   
 1,732 
   
 2,481 
   
 2,717 
Normal - Cooling (b)
 
 1,396 
   
 1,381 
   
 2,136 
   
 2,112 
                         
(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.

 
139

 

Third Quarter of 2012 Compared to Third Quarter of 2011
 
Reconciliation of Third Quarter of 2011 to Third Quarter of 2012
 
Net Income
 
(in millions)
 
       
Third Quarter of 2011
  $ 88  
         
Changes in Gross Margin:
       
Retail Margins (a)
    (9 )
Other Revenues
    (1 )
Total Change in Gross Margin
    (10 )
         
Changes in Expenses and Other:
       
Other Operation and Maintenance
    6  
Depreciation and Amortization
    (1 )
Taxes Other Than Income Taxes
    (4 )
Interest Income
    (1 )
Allowance for Equity Funds Used During Construction
    3  
Interest Expense
    (1 )
Total Change in Expenses and Other
    2  
         
Income Tax Expense
    9  
         
Third Quarter of 2012
  $ 89  
         
(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 $9 million primarily due to the following:
 
   
·
A $15 million decrease in weather-related usage primarily due to a 16% decrease in cooling degree days.
 
   
·
An $8 million decrease primarily due to wholesale fuel recovery adjustments.
 
   
These decreases were partially offset by:
   
·
A $7 million increase in municipal and cooperative revenues due to higher rates and formula rate adjustments.
   
·
A $7 million increase in retail revenues due to higher rates.

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

 
·
Other Operation and Maintenance expenses decreased $6 million primarily due to the following:
   
·
A $2 million decrease in generation plant maintenance expenses.
   
·
A $2 million decrease related to 2011 litigation expenses.
 
·
Taxes Other Than Income Taxes increased $4 million primarily due to favorable property tax adjustments made in the third quarter of 2011.
 
·
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 a decrease in pretax book income, the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis.

 
140

 

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011
 
Reconciliation of Nine Months Ended September 30, 2011 to Nine Months Ended September 30, 2012
Net Income
(in millions)
         
Nine Months Ended September 30, 2011
 
$
 169 
 
         
Changes in Gross Margin:
       
Retail Margins (a)
   
 (14)
 
Off-system Sales
   
 1 
 
Transmission Revenues
   
 2 
 
Other Revenues
   
 (1)
 
Total Change in Gross Margin
   
 (12)
 
         
Changes in Expenses and Other:
       
Other Operation and Maintenance
   
 19 
 
Asset Impairment and Other Related Charges
   
 (13)
 
Depreciation and Amortization
   
 (4)
 
Taxes Other Than Income Taxes
   
 (4)
 
Allowance for Equity Funds Used During Construction
   
 8 
 
Interest Expense
   
 (1)
 
Total Change in Expenses and Other
   
 5 
 
         
Income Tax Expense
   
 19 
 
         
Nine Months Ended September 30, 2012
 
$
 181 
 
         
(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 $14 million primarily due to the following:
 
   
·
A $22 million decrease in weather-related usage primarily due to a 51% decrease in heating degree days and a 9% decrease in cooling degree days.
 
   
·
A $13 million decrease primarily due to fuel expense adjustments.
 
   
These decreases were partially offset by:
   
·
A $16 million increase in municipal and cooperative revenues due to higher rates and formula rate adjustments.
   
·
A $5 million increase in retail revenues due to higher rates.

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

 
·
Other Operation and Maintenance expenses decreased $19 million primarily due to the following:
   
·
An $11 million decrease in generation maintenance expenses primarily due to higher 2011 planned and unplanned plant outages.
   
·
A $5 million decrease related to 2011 litigation expenses.
   
·
A $3 million decrease in distribution maintenance expenses primarily due to decreased vegetation management and storm-related expenses.
 
·
Asset Impairment and Other Related Charges includes the 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 $4 million primarily due to a greater depreciable base.
 
·
Taxes Other Than Income Taxes increased $4 million primarily due to favorable property tax adjustments made in the third quarter of 2011.
 
 
141

 
 
·
Allowance for Equity Funds Used During Construction increased $8 million primarily due to construction at the Turk Plant.
 
·
Income Tax Expense decreased $19 million primarily due to a decrease in pretax book income, the regulatory accounting treatment of state income taxes and other book tax differences which are accounted for on a flow-through basis.

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 207 for a discussion of accounting pronouncements.

 
142

 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
For the Three and Nine Months Ended September 30, 2012 and 2011
 
(in thousands)
 
(Unaudited)
 
   
   
Three Months Ended
   
Nine Months Ended
 
   
2012
   
2011
   
2012
   
2011
 
REVENUES
                       
Electric Generation, Transmission and Distribution
  $ 473,391     $ 512,767     $ 1,196,753     $ 1,248,031  
Sales to AEP Affiliates
    11,098       21,618       26,945       47,868  
Other Revenues
    680       597       1,403       1,572  
TOTAL REVENUES
    485,169       534,982       1,225,101       1,297,471  
                                 
EXPENSES
                               
Fuel and Other Consumables Used for Electric Generation
    180,991       213,004       447,233       486,729  
Purchased Electricity for Resale
    35,109       47,241       97,150       125,521  
Purchased Electricity from AEP Affiliates
    6,121       1,880       16,965       9,107  
Other Operation
    60,217       63,655       165,877       168,445  
Maintenance
    27,816       30,895       78,835       95,076  
Asset Impairment and Other Related Charges
    -       -       13,000       -  
Depreciation and Amortization
    35,144       33,919       103,820       99,927  
Taxes Other Than Income Taxes
    19,763       15,982       53,869       49,678  
TOTAL EXPENSES
    365,161       406,576       976,749       1,034,483  
                                 
OPERATING INCOME
    120,008       128,406       248,352       262,988  
                                 
Other Income (Expense):
                               
Interest Income
    39       1,070       1,171       1,181  
Allowance for Equity Funds Used During Construction
    15,216       12,692       43,401       34,861  
Interest Expense
    (21,498 )     (20,964 )     (65,210 )     (64,224 )
                                 
INCOME BEFORE INCOME TAX EXPENSE AND
                               
EQUITY EARNINGS
    113,765       121,204       227,714       234,806  
                                 
Income Tax Expense
    25,229       34,217       49,206       68,184  
Equity Earnings of Unconsolidated Subsidiary
    682       808       2,007       2,071  
                                 
NET INCOME
    89,218       87,795       180,515       168,693  
                                 
Net Income Attributable to Noncontrolling Interest
    955       1,023       3,099       3,141  
                                 
NET INCOME ATTRIBUTABLE TO SWEPCo
                               
SHAREHOLDERS
    88,263       86,772       177,416       165,552  
                                 
Preferred Stock Dividend Requirements
    -       58       -       172  
                                 
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON
                               
SHAREHOLDER
  $ 88,263     $ 86,714     $ 177,416     $ 165,380  
                                 
The common stock of SWEPCo is wholly-owned by AEP.
                               
                                 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 

 
143

 


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 
For the Three and Nine Months Ended September 30, 2012 and 2011
 
(in thousands)
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
2012
   
2011
   
2012
   
2011
 
Net Income
  $ 89,218     $ 87,795     $ 180,515     $ 168,693  
                                 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                               
Cash Flow Hedges, Net of Tax of $376 and $5,332 for the Three Months Ended
                               
September 30, 2012 and 2011, Respectively, and $367 and $5,195 for the
                               
Nine Months Ended September 30, 2012 and 2011, Respectively
    697       (9,903 )     (682 )     (9,648 )
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $90
                               
and $475 for the Three Months Ended September 30, 2012 and 2011,
                               
Respectively, and $269 and $206 for the Nine Months Ended September 30,
                               
2012 and 2011, Respectively
    167       (882 )     499       383  
                                 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
    864       (10,785 )     (183 )     (9,265 )
                                 
TOTAL COMPREHENSIVE INCOME
    90,082       77,010       180,332       159,428  
                                 
Total Comprehensive Income Attributable to Noncontrolling Interest
    955       1,023       3,099       3,141  
                                 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo
                               
SHAREHOLDERS
  $ 89,127     $ 75,987     $ 177,233     $ 156,287  
                                 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 

 
144

 


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
 
For the Nine Months Ended September 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
                                    (3,183 )     (3,183 )
Preferred Stock Dividends
                    (172 )                     (172 )
Subtotal – Equity
                                            1,663,994  
                                                 
Net Income
                    165,552               3,141       168,693  
Other Comprehensive Loss
                            (9,265 )             (9,265 )
TOTAL EQUITY – SEPTEMBER 30, 2011
  $ 135,660     $ 674,979     $ 1,034,220     $ (21,756 )   $ 319     $ 1,823,422  
                                                 
TOTAL EQUITY – DECEMBER 31, 2011
  $ 135,660     $ 674,606     $ 1,029,915     $ (26,815 )   $ 391     $ 1,813,757  
                                                 
Common Stock Dividends – Nonaffiliated
                                    (3,176 )     (3,176 )
Subtotal – Equity
                                            1,810,581  
                                                 
Net Income
                    177,416               3,099       180,515  
Other Comprehensive Loss
                            (183 )             (183 )
TOTAL EQUITY – SEPTEMBER 30, 2012
  $ 135,660     $ 674,606     $ 1,207,331     $ (26,998 )   $ 314     $ 1,990,913  
                                                 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 

 
145

 


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)
 
   
2012 
 
2011 
CURRENT ASSETS
           
Cash and Cash Equivalents
           
   
(September 30, 2012 Amount Includes $14,926 Related to Sabine)
 
$
 16,626 
 
$
 801 
Advances to Affiliates
   
 128,227 
   
 - 
Accounts Receivable:
           
   
Customers
   
 37,366 
   
 35,054 
   
Affiliated Companies
   
 18,607 
   
 23,730 
   
Miscellaneous
   
 37,973 
   
 19,370 
   
Allowance for Uncollectible Accounts
   
 (1,685)
   
 (989)
     
Total Accounts Receivable
   
 92,261 
   
 77,165 
Fuel
           
   
(September 30, 2012 and December 31, 2011 Amounts Include $24,229 and
           
   
$32,651, Respectively, Related to Sabine)
   
 112,278 
   
 102,015 
Materials and Supplies
   
 72,973 
   
 55,325 
Risk Management Assets
   
 705 
   
 445 
Deferred Income Tax Benefits
   
 6,664 
   
 8,195 
Accrued Tax Benefits
   
 38,376 
   
 1,541 
Regulatory Asset for Under-Recovered Fuel Costs
   
 8,382 
   
 10,843 
Prepayments and Other Current Assets
   
 23,657 
   
 16,827 
TOTAL CURRENT ASSETS
   
 500,149 
   
 273,157 
             
PROPERTY, PLANT AND EQUIPMENT
           
Electric:
           
   
Generation
   
 2,337,734 
   
 2,326,102 
   
Transmission
   
 1,102,142 
   
 988,534 
   
Distribution
   
 1,744,173 
   
 1,675,764 
Other Property, Plant and Equipment
           
   
(September 30, 2012 and December 31, 2011 Amounts Include $256,492 and
           
   
$232,948, Respectively, Related to Sabine)
   
 675,694 
   
 637,019 
Construction Work in Progress
   
 1,583,826 
   
 1,443,569 
Total Property, Plant and Equipment
   
 7,443,569 
   
 7,070,988 
Accumulated Depreciation and Amortization
           
   
(September 30, 2012 and December 31, 2011 Amounts Include $112,275 and
           
   
$103,586, Respectively, Related to Sabine)
   
 2,282,762 
   
 2,211,912 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
   
 5,160,807 
   
 4,859,076 
             
OTHER NONCURRENT ASSETS
           
Regulatory Assets
   
 430,013 
   
 394,276 
Long-term Risk Management Assets
   
 178 
   
 282 
Deferred Charges and Other Noncurrent Assets
   
 89,080 
   
 74,992 
TOTAL OTHER NONCURRENT ASSETS
   
 519,271 
   
 469,550 
             
TOTAL ASSETS
 
$
 6,180,227 
 
$
 5,601,783 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.
 
 
 
146

 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2012 and December 31, 2011
(Unaudited)
 
   
2012 
 
2011 
     
(in thousands)
CURRENT LIABILITIES
           
Advances from Affiliates
 
$
 - 
 
$
 132,473 
Accounts Payable:
           
   
General
   
 149,583 
   
 181,268 
   
Affiliated Companies
   
 40,076 
   
 59,201 
Short-term Debt – Nonaffiliated
   
 - 
   
 17,016 
Long-term Debt Due Within One Year – Nonaffiliated
   
 3,250 
   
 20,000 
Risk Management Liabilities
   
 4,148 
   
 24,359 
Customer Deposits
   
 53,187 
   
 52,095 
Accrued Taxes
   
 53,188 
   
 44,404 
Accrued Interest
   
 19,182 
   
 39,629 
Obligations Under Capital Leases
   
 17,426 
   
 15,058 
Regulatory Liability for Over-Recovered Fuel Costs
   
 13,000 
   
 5,032 
Other Current Liabilities
   
 65,615 
   
 64,413 
TOTAL CURRENT LIABILITIES
   
 418,655 
   
 654,948 
             
NONCURRENT LIABILITIES
           
Long-term Debt – Nonaffiliated
   
 2,042,889 
   
 1,708,637 
Long-term Risk Management Liabilities
   
 134 
   
 221 
Deferred Income Taxes
   
 926,183 
   
 665,668 
Regulatory Liabilities and Deferred Investment Tax Credits
   
 469,652 
   
 428,571 
Asset Retirement Obligations
   
 80,359 
   
 65,673 
Employee Benefits and Pension Obligations
   
 81,257 
   
 87,159 
Obligations Under Capital Leases
   
 116,750 
   
 112,802 
Deferred Credits and Other Noncurrent Liabilities
   
 53,435 
   
 64,347 
TOTAL NONCURRENT LIABILITIES
   
 3,770,659 
   
 3,133,078 
             
TOTAL LIABILITIES
   
 4,189,314 
   
 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
   
 1,207,331 
   
 1,029,915 
Accumulated Other Comprehensive Income (Loss)
   
 (26,998)
   
 (26,815)
TOTAL COMMON SHAREHOLDER’S EQUITY
   
 1,990,599 
   
 1,813,366 
             
Noncontrolling Interest
   
 314 
   
 391 
             
TOTAL EQUITY
   
 1,990,913 
   
 1,813,757 
             
TOTAL LIABILITIES AND EQUITY
 
$
 6,180,227 
 
$
 5,601,783 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.

 
147

 


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2012 and 2011
(in thousands)
(Unaudited)
 
   
2012 
 
2011 
OPERATING ACTIVITIES
           
Net Income
 
$
 180,515 
 
$
 168,693 
Adjustments to Reconcile Net Income to Net Cash Flows from
           
 
 Operating Activities:
           
   
Depreciation and Amortization
   
 103,820 
   
 99,927 
   
Deferred Income Taxes
   
 215,283 
   
 36,979 
   
Asset Impairment and Other Related Charges
   
 13,000 
   
 - 
   
Allowance for Equity Funds Used During Construction
   
 (43,401)
   
 (34,861)
   
Mark-to-Market of Risk Management Contracts
   
 (1,179)
   
 (3,148)
   
Fuel Over/Under-Recovery, Net
   
 10,429 
   
 (30,259)
   
Change in Other Noncurrent Assets
   
 2,355 
   
 19,606 
   
Change in Other Noncurrent Liabilities
   
 25,945 
   
 32,685 
   
Changes in Certain Components of Working Capital:
           
     
Accounts Receivable, Net
   
 (15,071)
   
 9,718 
     
Fuel, Materials and Supplies
   
 (27,911)
   
 (10,508)
     
Accounts Payable
   
 (13,474)
   
 2,906 
     
Accrued Taxes, Net
   
 (24,649)
   
 68,674 
     
Accrued Interest
   
 (20,473)
   
 (22,240)
     
Other Current Assets
   
 (7,940)
   
 (3,356)
     
Other Current Liabilities
   
 (12,570)
   
 (2,545)
Net Cash Flows from Operating Activities
   
 384,679 
   
 332,271 
             
INVESTING ACTIVITIES
           
Construction Expenditures
   
 (395,829)
   
 (395,193)
Change in Advances to Affiliates, Net
   
 (128,227)
   
 86,222 
Other Investing Activities
   
 1,240 
   
 (3,479)
Net Cash Flows Used for Investing Activities
   
 (522,816)
   
 (312,450)
             
FINANCING ACTIVITIES
           
Issuance of Long-term Debt – Nonaffiliated
   
 336,429 
   
 - 
Credit Facility Borrowings
   
 21,462 
   
 32,532 
Change in Advances from Affiliates, Net
   
 (132,473)
   
 41,537 
Retirement of Long-term Debt – Nonaffiliated
   
 (21,625)
   
 (41,135)
Retirement of Cumulative Preferred Stock
   
 - 
   
 (2)
Credit Facility Repayments
   
 (38,478)
   
 (38,749)
Principal Payments for Capital Lease Obligations
   
 (12,036)
   
 (10,029)
Dividends Paid on Common Stock – Nonaffiliated
   
 (3,176)
   
 (3,183)
Dividends Paid on Cumulative Preferred Stock
   
 - 
   
 (172)
Other Financing Activities
   
 3,859 
   
 3,650 
Net Cash Flows from (Used for) Financing Activities
   
 153,962 
   
 (15,551)
             
Net Increase in Cash and Cash Equivalents
   
 15,825 
   
 4,270 
Cash and Cash Equivalents at Beginning of Period
   
 801 
   
 1,514 
Cash and Cash Equivalents at End of Period
 
$
 16,626 
 
$
 5,784 
             
SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 74,656 
 
$
 78,239 
Net Cash Paid (Received) for Income Taxes
   
 (112,290)
   
 (8,586)
Noncash Acquisitions Under Capital Leases
   
 18,560 
   
 10,296 
Construction Expenditures Included in Current Liabilities at September 30,
   
 72,318 
   
 99,600 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 150.

 
148

 

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 150.

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


 
149

 

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.
Acquisition and Impairments
APCo, OPCo, SWEPCo
5.
Benefit Plans
APCo, I&M, OPCo, PSO, SWEPCo
6.
Business Segments
APCo, I&M, OPCo, PSO, SWEPCo
7.
Derivatives and Hedging
APCo, I&M, OPCo, PSO, SWEPCo
8.
Fair Value Measurements
APCo, I&M, OPCo, PSO, SWEPCo
9.
Income Taxes
APCo, I&M, OPCo, PSO, SWEPCo
10.
Financing Activities
APCo, I&M, OPCo, PSO, SWEPCo
11.
Sustainable Cost Reductions
APCo, I&M, OPCo, PSO, SWEPCo

 
150

 
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 nine months ended September 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 September 30, 2012 and 2011 were $35 million and $33 million, respectively, and for the nine months ended September 30, 2012 and 2011 were $126 million and $97 million, respectively.  See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets.

 
151

 
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
September 30, 2012 and December 31, 2011
(in thousands)
   
Sabine
ASSETS
 
2012 
 
2011 
Current Assets
 
$
 71,026 
 
$
 48,044 
Net Property, Plant and Equipment
   
 174,743 
   
 153,715 
Other Noncurrent Assets
   
 56,687 
   
 42,574 
Total Assets
 
$
 302,456 
 
$
 244,333 
             
LIABILITIES AND EQUITY
           
Current Liabilities
 
$
 45,033 
 
$
 67,779 
Noncurrent Liabilities
   
 257,109 
   
 176,163 
Equity
   
 314 
   
 391 
Total Liabilities and Equity
 
$
 302,456 
 
$
 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 September 30, 2012 and 2011 were $23 million and $6 million, respectively, and for the nine months ended September 30, 2012 and 2011 were $82 million and $49 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
September 30, 2012 and December 31, 2011
(in thousands)
   
DCC Fuel
ASSETS
 
2012 
 
2011 
Current Assets
 
$
 154,774 
 
$
 118,144 
Net Property, Plant and Equipment
   
 208,185 
   
 188,375 
Other Noncurrent Assets
   
 113,519 
   
 117,772 
Total Assets
 
$
 476,478 
 
$
 424,291 
             
LIABILITIES AND EQUITY
           
Current Liabilities
 
$
 128,466 
 
$
 102,946 
Noncurrent Liabilities
   
 348,012 
   
 321,345 
Equity
   
 - 
   
 - 
Total Liabilities and Equity
 
$
 476,478 
 
$
 424,291 

 
152

 
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 September 30, 2012 and 2011 were $20 million and $18 million, respectively, and for the nine months ended September 30, 2012 and 2011 were $54 million and $47 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:

   
September 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
   
 1,126 
   
 1,126 
   
 1,120 
   
 1,120 
SWEPCo's Guarantee of Debt
   
 - 
   
 53,278 
   
 - 
   
 52,310 
                         
Total Investment in DHLC
 
$
 8,769 
 
$
 62,047 
 
$
 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 September 30,
 
Nine Months Ended September 30,
Company
 
2012 
 
2011 
 
2012 
 
2011 
   
(in thousands)
APCo
 
$
 47,820 
 
$
 52,105 
 
$
 130,260 
 
$
 144,398 
I&M
   
 31,134 
   
 32,127 
   
 88,618 
   
 94,961 
OPCo
   
 72,751 
   
 73,664 
   
 193,686 
   
 210,533 
PSO
   
 21,728 
   
 21,924 
   
 60,625 
   
 62,471 
SWEPCo
   
 33,154 
   
 35,101 
   
 93,120 
   
 96,494 

 
153

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

   
September 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
 
$
 18,989 
 
$
 18,989 
 
$
 20,812 
 
$
 20,812 
I&M
   
 12,654 
   
 12,654 
   
 13,741 
   
 13,741 
OPCo
   
 27,379 
   
 27,379 
   
 29,823 
   
 29,823 
PSO
   
 9,105 
   
 9,105 
   
 9,280 
   
 9,280 
SWEPCo
   
 14,054 
   
 14,054 
   
 14,699 
   
 14,699 

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 September 30,
 
Nine Months Ended September 30,
Company
 
2012 
 
2011 
 
2012 
 
2011 
   
(in thousands)
I&M
 
$
 65,051 
 
$
 64,948 
 
$
 177,790 
 
$
 167,620 
OPCo
   
 46,184 
   
 47,712 
   
 149,424 
   
 139,729 

The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows:
 
   
September 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
 
$
 22,450 
 
$
 22,450 
 
$
 25,731 
 
$
 25,731 
OPCo
   
 12,006 
   
 12,006 
   
 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.
 
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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
       
September 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
           
 
Expanded Net Energy Charge
 
$
8,775 
 
$
 - 
Regulatory Assets Currently Not Earning a Return
           
 
Storm Related Costs
   
 62,400 
   
 - 
 
Virginia Environmental Rate Adjustment Clause
   
 23,204 
   
 17,950 
 
Mountaineer Carbon Capture and Storage
           
   
Product Validation Facility
   
 14,155 
   
 14,155 
 
Special Rate Mechanism for Century Aluminum
   
 13,002 
   
 12,811 
 
Dresden Operating Costs
   
 8,758 
   
 - 
 
Virginia Deferred Wind Power Costs
   
 4,355 
   
 38,192 
 
Transmission Agreement Phase-In
   
 2,803 
   
 1,925 
 
Mountaineer Carbon Capture and Storage
           
   
Commercial Scale Facility
   
 1,291 
   
 1,335 
 
Other Regulatory Assets Not Yet Being Recovered
   
 1,308 
   
 1,010 
Total Regulatory Assets Not Yet Being Recovered
 
$
 140,051 
 
$
 87,378 

       
I&M
       
September 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
 
$
 11,027 
 
$
 10,803 
 
Mountaineer Carbon Capture and Storage
           
   
Commercial Scale Facility
   
 1,384 
   
 1,680 
 
Other Regulatory Asset Not Yet Being Recovered
   
 899 
   
 - 
Total Regulatory Assets Not Yet Being Recovered
 
$
 13,310 
 
$
 12,483 

 
155

 
       
OPCo
       
September 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
 
$
 13,053 
 
$
 12,572 
Regulatory Assets Currently Not Earning a Return
           
 
Storm Related Costs
   
 53,600 
   
 8,375 
Total Regulatory Assets Not Yet Being Recovered
 
$
 66,653 
 
$
 20,947 

       
PSO
       
September 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
           
 
Environmental Compliance Costs
 
$
 351 
 
$
 - 
Total Regulatory Assets Not Yet Being Recovered
 
$
 351 
 
$
 - 

       
SWEPCo
       
September 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
 
$
 3,673 
 
$
 - 
 
Mountaineer Carbon Capture and Storage
           
   
Commercial Scale Facility
   
 2,301 
   
 2,380 
 
Other Regulatory Assets Not Yet Being Recovered
   
 2,099 
   
 1,699 
Total Regulatory Assets Not Yet Being Recovered
 
$
 8,073 
 
$
 4,079 

If these costs are ultimately determined not to be recoverable, it would reduce future net income and cash flows and impact financial condition.
 
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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 result in a refund of 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 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.

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 one month after the PUCO issues an order on the 2010 SEET.  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.  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 addressed in a separate PIRR docket.
 
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In August 2012, the PUCO ordered implementation of PIRR rates beginning September 2012.  The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin.  The August 2012 order was upheld on rehearing by the PUCO in October 2012.  As of September 30, 2012, OPCo’s net PIRR deferral was $536 million, excluding unrecognized equity carrying costs.

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 the Partnership with Ohio and the Ohio Growth Fund and an $8 million regulatory asset for 2011 storm damage, both originally recorded in the fourth quarter of 2011.

June 2012 – May 2015 ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that will freeze base generation rates through May 2015, adopt a 12% earnings threshold for the SEET and allow the continuation of the fuel adjustment clause.  Further, the ESP established a non-bypassable Distribution Investment Rider effective September 2012 through May 2015 to recover, with certain caps, post-August 2010 distribution investment.  The ESP also maintained recovery of several previous ESP riders and required OPCo to contribute $2 million per year during the ESP to the Ohio Growth Fund.  In addition, the ESP approved a storm damage recovery mechanism which allowed OPCo to defer the majority of the incremental distribution operation and maintenance costs from 2012 storms.  As of September 30, 2012, OPCo recorded $54 million in Regulatory Assets on the condensed balance sheets related to the 2012 storm damage.  If OPCo is not ultimately permitted to recover these storm costs, it would reduce future net income and cash flows and impact financial condition.

As part of the ESP decision, the PUCO ordered OPCo to conduct an energy-only auction for 10% of the SSO load with delivery beginning six months after the receipt of ESP and corporate separation orders and extending through December 2014.  The PUCO also ordered OPCo to conduct an energy-only auction for a total of 60% of the SSO load with delivery beginning June 2014 through May 2015.  In addition, the PUCO ordered OPCo to conduct an energy-only auction for the remaining 40% of the SSO load for delivery from January 2015 through May 2015.  Starting in June 2015, OPCo will conduct energy and capacity auctions for its entire SSO load.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of 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 June 2012 – May 2015 ESP proceeding.  In July 2012, several parties, including OPCo, requested rehearing of the July 2012 PUCO order on capacity, which was upheld by the PUCO in October 2012.

In the August 2012 PUCO order which adopted and modified the new ESP, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR is intended to provide $508 million over the ESP period and will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the deferred capacity costs.  In August 2012, the IEU filed a claim before the Supreme Court of Ohio stating, among other things, that OPCo’s collection of its capacity costs is illegal.  In September 2012, OPCo and the PUCO filed motions to dismiss IEU’s claim.  If OPCo is ultimately not permitted to fully collect its deferred capacity costs, it would reduce future net income and cash flows and impact financial condition.

In September 2012, OPCo and intervenors filed applications with the PUCO for rehearing of the August 2012 ESP order.  Rehearing of this order is pending at the PUCO.  If OPCo is ultimately not permitted to fully collect its ESP rates, including the RSR, it would reduce future net income and cash flows and impact financial condition.
 
158

 
Proposed Corporate Separation

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.  In October 2012, the PUCO issued an order which approved the transfer of OPCo’s generation assets at net book value to AEP Generation Resources, Inc. (AEPGenCo), a nonregulated affiliate in the Generation and Marketing segment.  AEPGenCo will also assume the associated generation liabilities.

An additional filing at the FERC related to corporate separation is expected in the fourth quarter of 2012.  Prior to corporate separation, OPCo’s results of operations related to generation could be affected by the ability to sell power and capacity at a profit at rates determined by the prevailing market.  If power and capacity are not sold at a profit, it could reduce OPCo’s future net income and cash flows and impact financial condition.

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.

Since the February 2012 PUCO order rejected the ESP modified stipulation, collection of the DIR terminated.  In August 2012, the PUCO approved a new DIR as filed in the ESP proceeding.  The DIR is capped at $86 million in 2012, $104 million in 2013, $124 million in 2014 and $52 million for the period January through May 2015, for a total of $366 million.  See the “June 2012 – May 2015 ESP Including Capacity Charge” section above.

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 August 2012, an intervenor filed with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges, which, if ordered, would be $35 million plus carrying charges.  If the Supreme Court of Ohio ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audits reports which 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 September 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 $38 million, including $20 million of unrecognized equity carrying costs.  These amounts include the carrying costs exposure of the 2009 FAC audit, which has been appealed by an intervenor to the Supreme Court of Ohio.  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.
 
159

 
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 September 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 $122 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $122 million for transmission, excluding AFUDC.  As of September 30, 2012, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital costs cap, SWEPCo has capitalized approximately $1.7 billion of expenditures, including AFUDC and capitalized interest of $296 million for generation and related transmission costs of $127 million.  As of September 30, 2012, the joint owners and SWEPCo have contractual construction obligations of approximately $42 million, including related transmission costs of $3 million.  SWEPCo’s share of the contractual construction obligations is $31 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 from the Turk Plant.  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 options.
 
160

 
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.  The Supreme Court of Texas has requested full briefing from the parties.

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 included a return on and of the Texas jurisdictional share of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operations and maintenance costs.  The filing also (a) increased depreciation expense due to the decrease in the average remaining life of the Welsh Plant to account for the change in the retirement date of the Welsh Plant, Unit 2 from 2040 to 2016, (b) proposed increased vegetation management expenditures recovered from ratepayers and (c) included a return on and of the Stall Unit as of December 2011 and associated operations and maintenance costs.

In September 2012, an Administrative Law Judge issued an order that granted the establishment of SWEPCo’s existing rates as temporary rates beginning in late January 2013, subject to true-up to the final PUCT-approved rates.  A decision from the PUCT is expected in the second quarter of 2013.  If the PUCT does not approve full cost recovery of SWEPCo’s assets, it could reduce future net income and cash flows and impact financial condition.

Flint Creek Plant Environmental Controls

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 September 30, 2012, SWEPCo has incurred $10 million related to this project, including AFUDC.  The APSC staff and the Sierra Club filed testimony that recommended the APSC deny the requested declaratory order.  A hearing at the APSC was held in October 2012 and a decision is pending from the APSC.  If SWEPCo is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

Louisiana 2010 Formula Rate Filing

In April 2010, SWEPCo filed its 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.  A settlement agreement was reached by the parties and orally approved by the LPSC in September 2012.  The reserve recorded in the second quarter of 2012 was increased by an immaterial amount to cover the $3 million refund approved by the LPSC in the settlement agreement.  The refund began in October 2012 and will occur over a twelve-month period.
 
161

 
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 (Environmental 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.  A decision is expected in the fourth quarter of 2012.  If the Supreme Court of Virginia were to issue a favorable decision, it could increase future net income and cash flows.

Generation Rate Adjustment Clause (Generation RAC)

In January 2012, the Virginia SCC issued a generation RAC order which allowed APCo to recover $26 million annually, effective March 2012, related to recovery of the Dresden Plant.  In March 2012, APCo filed with the Virginia SCC to continue the current generation RAC rate to recover costs of the Dresden Plant through February 2014.  In August 2012, the Virginia SCC staff filed testimony that recommended a $5 million increase in the revenue requirement, including the under-recovered balance of $3 million as of April 2012.  The Virginia SCC staff also recommended an alternative proposal to not change rates and not allow APCo to accrue carrying charges on any under-recovered generation RAC balances.  A decision is expected in the fourth quarter of 2012.  If the Virginia SCC were to disallow any portion of the generation RAC, it could reduce future net income and cash flows and impact financial condition.

APCo’s Filings for an IGCC Plant

Through September 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.  If the financing order is not issued, APCo and WPCo requested that recovery of these costs be allowed in current rates.

In July 2012, the WVPSC issued an interim order that approved a settlement agreement 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.  In August 2012, APCo and WPCo filed with the WVPSC a request for a financing order to securitize $422 million related to the December 2011 under-recovered ENEC deferral balance, other ENEC-related assets and related financing costs.  Upon completion of the securitization, APCo would offset its current ENEC rates by an amount to recover the securitized balance over the securitization period.  As of September 30, 2012, APCo’s ENEC under-recovery balance of $307 million was recorded in Regulatory Assets on the condensed balance sheet, excluding $5 million of unrecognized equity carrying costs.  A hearing is scheduled for December 2012.
 
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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 fourth quarter of 2012.

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%.  In October 2012, the OCC issued a final order that found PSO’s fuel and purchased power costs were prudently incurred without any disallowance and that PSO’s shareholder’s portion of off-system sales margins would remain at 25%.

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 an increase of approximately $25 million in annual depreciation expense.  Included in the depreciation rates increase was a decrease in the average remaining life of Tanners Creek Plant to account for the change in the retirement date of Tanners Creek Plant, Units 1-3 from 2020 to 2014.  In May 2012, I&M filed rebuttal testimony which changed the retirement date for Tanners Creek Plant, Units 1-3 to 2015.

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.  If the IURC disallows cost recovery, it could reduce future net income and cash flows and impact financial condition.

Cook Plant 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 Need and authorize I&M to defer, on an interim basis, incremental depreciation and related property tax costs, including interest, along with study, analysis and development costs until the applicable LCM costs are included in I&M’s base rates.  As of September 30, 2012, I&M has incurred $109 million related to the LCM Project, including AFUDC.
 
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In August 2012, intervenors filed testimony in Indiana.  The Indiana Michigan Power Company Industrial Group recommended that I&M recover $229 million in a rider with the remaining costs requested in future base rate cases.  The Indiana Office of Utility Consumer Counselor (OUCC) recommended a maximum of $408 million of LCM project costs be recovered in a rider, and a maximum of $299 million for projects the OUCC believes are not related to LCM to be recovered in future base rates.  A hearing at the IURC is scheduled for January 2013.

Also in August 2012, the MPSC staff and other intervenors filed testimony in Michigan.  The recommendations ranged from the Association of Businesses Advocating Tariff Equity’s denial of deferral of costs but recovery of costs considered in future base rate cases to the Attorney General allowing recovery of LCM project costs of $848 million.  If I&M is not ultimately permitted to recover its LCM Project costs, it would reduce future net income and cash flows.

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 September 30, 2012, I&M has incurred $24 million, including AFUDC.  If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

In July 2012, certain intervenors filed testimony which recommended cost 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 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.  A hearing is scheduled for December 2012.

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 

 
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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.  A decision is pending from the FERC.  APCo’s, I&M’s and OPCo’s portions of potential refund payments are as follows:

   
Potential
   
Refund
Company
 
Payments
   
(in millions)
APCo
 
$
 6.4 
I&M
   
 3.7 
OPCo
   
 8.3 

Not all parties have agreed to the compliance filing.  In August 2012, the FERC issued an order approving a settlement agreement resulting in the AEP East companies’ October 2012 collection of $8 million of previously deemed uncollectible SECA revenue.  There was no change in the reserve for net refunds due to the remaining uncertainty around negotiations with certain parties who have not agreed to the compliance filing.  The balance in the reserve for future settlements as of September 30, 2012 was $31 million.  APCo’s, I&M’s and OPCo’s reserve balances as of September 30, 2012 were:

Company
 
September 30, 2012
   
(in millions)
APCo
 
$
 10.0 
I&M
   
 5.9 
OPCo
   
 13.1 

Based on the analysis of the May 2010 order, the compliance filing and recent settlements, 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.  Management intends to file an application with the FERC in the fourth quarter of 2012 to terminate the Interconnection Agreement.  It is unknown 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 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

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 September 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
OPCo
   
 2,102 
 
June 2013
SWEPCo
   
 4,448 
 
March 2013

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 September 30, 2012, SWEPCo has collected approximately $58 million through a rider for final mine closure and reclamation costs, of which $10 million is recorded in Other Current Liabilities, $7 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $41 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.
 
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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 September 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.

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 September 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
 
$
 3,132 
I&M
   
 2,426 
OPCo
   
 3,556 
PSO
   
 1,167 
SWEPCo
   
 2,559 

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 September 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.
 
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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.

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.  In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court’s decision, holding that the CAA displaced Kivalina’s claims for damages.  Plaintiffs have filed a petition for rehearing by the full court.  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.
 
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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.

I&M maintains insurance through NEIL.  As of September 30, 2012, I&M recorded $64 million on its condensed balance sheet representing amounts recoverable from NEIL under the insurance policies.  Through September 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.  ACQUISITION AND IMPAIRMENTS

ACQUISITION

2011

Dresden Plant – Affecting APCo

In August 2011, APCo purchased the partially completed Dresden Plant from AEGCo, at cost, for $302 million.  The Dresden Plant was completed and placed in service in January 2012.  The Dresden Plant is located near Dresden, Ohio and is a natural gas, combined cycle power plant with a generating capacity of 580 MW.

IMPAIRMENTS

2012

Turk Plant (Utility Operations segment) – Affecting SWEPCo

In 2012, SWEPCo recorded a pretax write-off of $13 million in Asset Impairments and Other Related Charges on the condensed statements of income related to unrecoverable construction costs subject to the Texas capital costs cap portion of the Turk Plant.
 
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2011

Muskingum River Plant Unit 5 FGD Project (MR5) – Affecting OPCo

In September 2011, subsequent to the stipulation agreement filed with the PUCO, management determined that OPCo was not likely to complete the previously suspended MR5 project and that the project’s preliminary engineering costs were no longer probable of being recovered.  As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $42 million in Asset Impairments and Other Related Charges on the condensed statements of income.

Sporn Plant Unit 5 – Affecting OPCo

In the third quarter of 2011, management decided to no longer offer the output of Sporn Unit 5 into the PJM market.  Sporn Unit 5 is not expected to operate in the future, resulting in the removal of Sporn Unit 5 from the Interconnection Agreement.  As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $48 million in Asset Impairments and Other Related Charges on the condensed statements of income.

5.  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 nine months ended September 30, 2012 and 2011:

APCo
   
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2012 
 
2011 
 
2012 
 
2011 
 
(in thousands)
Service Cost
$
 1,892 
 
$
 1,799 
 
$
 1,346 
 
$
 1,245 
Interest Cost
 
 7,553 
   
 8,073 
   
 4,616 
   
 4,867 
Expected Return on Plan Assets
 
 (10,486)
   
 (10,458)
   
 (4,188)
   
 (4,496)
Amortization of Transition Obligation
 
 - 
   
 - 
   
 201 
   
 286 
Amortization of Prior Service Cost (Credit)
 
 118 
   
 230 
   
 (716)
   
 (42)
Amortization of Net Actuarial Loss
 
 5,085 
   
 4,142 
   
 2,631 
   
 1,465 
Net Periodic Benefit Cost
$
 4,162 
 
$
 3,786 
 
$
 3,890 
 
$
 3,325 

     
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2012 
 
2011 
 
2012 
 
2011 
 
(in thousands)
Service Cost
$
 5,674 
 
$
 5,399 
 
$
 4,040 
 
$
 3,737 
Interest Cost
 
 22,659 
   
 24,219 
   
 13,847 
   
 14,601 
Expected Return on Plan Assets
 
 (31,458)
   
 (31,374)
   
 (12,564)
   
 (13,488)
Amortization of Transition Obligation
 
 - 
   
 - 
   
 601 
   
 859 
Amortization of Prior Service Cost (Credit)
 
 356 
   
 688 
   
 (2,147)
   
 (128)
Amortization of Net Actuarial Loss
 
 15,254 
   
 12,427 
   
 7,894 
   
 4,379 
Net Periodic Benefit Cost
$
 12,485 
 
$
 11,359 
 
$
 11,671 
 
$
 9,960 

 
170

 
I&M
   
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2012 
 
2011 
 
2012 
 
2011 
 
(in thousands)
Service Cost
$
 2,477 
 
$
 2,362 
 
$
 1,655 
 
$
 1,531 
Interest Cost
 
 6,562 
   
 6,931 
   
 3,196 
   
 3,402 
Expected Return on Plan Assets
 
 (9,392)
   
 (9,213)
   
 (3,212)
   
 (3,471)
Amortization of Transition Obligation
 
 - 
   
 - 
   
 33 
   
 47 
Amortization of Prior Service Cost (Credit)
 
 101 
   
 186 
   
 (595)
   
 (59)
Amortization of Net Actuarial Loss
 
 4,392 
   
 3,536 
   
 1,762 
   
 891 
Net Periodic Benefit Cost
$
 4,140 
 
$
 3,802 
 
$
 2,839 
 
$
 2,341 

     
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2012 
 
2011 
 
2012 
 
2011 
 
(in thousands)
Service Cost
$
 7,431 
 
$
 7,085 
 
$
 4,965 
 
$
 4,590 
Interest Cost
 
 19,684 
   
 20,794 
   
 9,589 
   
 10,207 
Expected Return on Plan Assets
 
 (28,175)
   
 (27,641)
   
 (9,635)
   
 (10,414)
Amortization of Transition Obligation
 
 - 
   
 - 
   
 99 
   
 141 
Amortization of Prior Service Cost (Credit)
 
 305 
   
 558 
   
 (1,787)
   
 (177)
Amortization of Net Actuarial Loss
 
 13,177 
   
 10,608 
   
 5,287 
   
 2,674 
Net Periodic Benefit Cost
$
 12,422 
 
$
 11,404 
 
$
 8,518 
 
$
 7,021 

OPCo
   
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2012 
 
2011 
 
2012 
 
2011 
 
(in thousands)
Service Cost
$
 2,751 
 
$
 2,557 
 
$
 2,187 
 
$
 1,957 
Interest Cost
 
 11,298 
   
 12,087 
   
 6,047 
   
 6,375 
Expected Return on Plan Assets
 
 (17,100)
   
 (16,364)
   
 (5,639)
   
 (6,129)
Amortization of Transition Obligation
 
 - 
   
 - 
   
 26 
   
 37 
Amortization of Prior Service Cost (Credit)
 
 186 
   
 368 
   
 (969)
   
 (53)
Amortization of Net Actuarial Loss
 
 7,610 
   
 6,207 
   
 3,418 
   
 2,265 
Net Periodic Benefit Cost
$
 4,745 
 
$
 4,855 
 
$
 5,070 
 
$
 4,452 

     
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2012 
 
2011 
 
2012 
 
2011 
 
(in thousands)
Service Cost
$
 8,253 
 
$
 7,672 
 
$
 6,561 
 
$
 5,870 
Interest Cost
 
 33,895 
   
 36,263 
   
 18,142 
   
 19,123 
Expected Return on Plan Assets
 
 (51,301)
   
 (49,097)
   
 (16,917)
   
 (18,385)
Amortization of Transition Obligation
 
 - 
   
 - 
   
 78 
   
 112 
Amortization of Prior Service Cost (Credit)
 
 557 
   
 1,104 
   
 (2,905)
   
 (160)
Amortization of Net Actuarial Loss
 
 22,830 
   
 18,621 
   
 10,252 
   
 5,914 
Net Periodic Benefit Cost
$
 14,234 
 
$
 14,563 
 
$
 15,211 
 
$
 12,474 

 
171

 
PSO
   
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2012 
 
2011 
 
2012 
 
2011 
 
(in thousands)
Service Cost
$
 1,487 
 
$
 1,440 
 
$
 709 
 
$
 655 
Interest Cost
 
 3,076 
   
 3,321 
   
 1,449 
   
 1,512 
Expected Return on Plan Assets
 
 (4,503)
   
 (4,366)
   
 (1,480)
   
 (1,566)
Amortization of Prior Service Credit
 
 (237)
   
 (238)
   
 (270)
   
 (19)
Amortization of Net Actuarial Loss
 
 2,051 
   
 1,690 
   
 797 
   
 389 
Net Periodic Benefit Cost
$
 1,874 
 
$
 1,847 
 
$
 1,205 
 
$
 971 

     
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2012 
 
2011 
 
2012 
 
2011 
 
(in thousands)
Service Cost
$
 4,463 
 
$
 4,320 
 
$
 2,127 
 
$
 1,966 
Interest Cost
 
 9,226 
   
 9,964 
   
 4,348 
   
 4,535 
Expected Return on Plan Assets
 
 (13,511)
   
 (13,098)
   
 (4,441)
   
 (4,698)
Amortization of Prior Service Credit
 
 (711)
   
 (713)
   
 (809)
   
 (57)
Amortization of Net Actuarial Loss
 
 6,154 
   
 5,068 
   
 2,391 
   
 1,165 
Net Periodic Benefit Cost
$
 5,621 
 
$
 5,541 
 
$
 3,616 
 
$
 2,911 

SWEPCo
   
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2012 
 
2011 
 
2012 
 
2011 
 
(in thousands)
Service Cost
$
 1,775 
 
$
 1,644 
 
$
 831 
 
$
 757 
Interest Cost
 
 3,134 
   
 3,333 
   
 1,669 
   
 1,742 
Expected Return on Plan Assets
 
 (4,717)
   
 (4,596)
   
 (1,699)
   
 (1,800)
Amortization of Prior Service Cost (Credit)
 
 (198)
   
 (199)
   
 (234)
   
 64 
Amortization of Net Actuarial Loss
 
 2,083 
   
 1,690 
   
 915 
   
 447 
Net Periodic Benefit Cost
$
 2,077 
 
$
 1,872 
 
$
 1,482 
 
$
 1,210 

     
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2012 
 
2011 
 
2012 
 
2011 
 
(in thousands)
Service Cost
$
 5,324 
 
$
 4,930 
 
$
 2,493 
 
$
 2,271 
Interest Cost
 
 9,403 
   
 9,999 
   
 5,005 
   
 5,227 
Expected Return on Plan Assets
 
 (14,150)
   
 (13,786)
   
 (5,096)
   
 (5,400)
Amortization of Prior Service Cost (Credit)
 
 (595)
   
 (597)
   
 (700)
   
 193 
Amortization of Net Actuarial Loss
 
 6,248 
   
 5,070 
   
 2,744 
   
 1,339 
Net Periodic Benefit Cost
$
 6,230 
 
$
 5,616 
 
$
 4,446 
 
$
 3,630 

6.  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.
 
172

 
7.  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

Risk Management Strategies

The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  The risk management strategies also include the use of derivative instruments for trading purposes, focusing 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.  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.
 
173

 
The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of September 30, 2012 and December 31, 2011:

Notional Volume of Derivative Instruments
September 30, 2012
                                       
Primary Risk
 
Unit of
                             
Exposure
 
Measure
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
           
(in thousands)
Commodity:
                                 
 
Power
 
MWHs
   
 142,425 
   
 98,176 
   
 200,993 
   
 14 
   
 16 
 
Coal
 
Tons
   
 2,498 
   
 2,944 
   
 5,052 
   
 2,416 
   
 2,241 
 
Natural Gas
 
MMBtus
   
 11,127 
   
 7,647 
   
 15,703 
   
 13 
   
 15 
 
Heating Oil and
                                 
   
Gasoline
 
Gallons
   
 858 
   
 440 
   
 1,041 
   
 494 
   
 471 
 
Interest Rate
 
USD
 
$
 29,011 
 
$
 19,936 
 
$
 40,940 
 
$
 - 
 
$
 - 
                                       
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.
 
174

 
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 September 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:

     
September 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
 
$
 2,375 
 
$
 10,408 
 
$
 4,291 
 
$
 28,964 
I&M
   
 1,632 
   
 7,151 
   
 2,752 
   
 18,547 
OPCo
   
 3,352 
   
 14,687 
   
 5,810 
   
 39,183 
PSO
   
 5 
   
 9 
   
 53 
   
 130 
SWEPCo
   
 6 
   
 9 
   
 66 
   
 124 

 
175

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

Fair Value of Derivative Instruments
September 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
 
$
165,813 
 
$
1,307 
 
$
 
$
(135,893)
 
$
31,227 
Long-term Risk Management Assets
   
82,738 
   
291 
   
   
(44,658)
   
38,371 
Total Assets
   
248,551 
   
1,598 
   
   
(180,551)
   
69,598 
                                 
Current Risk Management Liabilities
   
157,836 
   
1,757 
   
   
(141,267)
   
18,326 
Long-term Risk Management Liabilities
   
68,293 
   
419 
   
   
(47,907)
   
20,805 
Total Liabilities
   
226,129 
   
2,176 
   
   
(189,174)
   
39,131 
                                 
Total MTM Derivative Contract Net
                             
 
Assets (Liabilities)
 
$
22,422 
 
$
(578)
 
$
 
$
8,623 
 
$
30,467 
                                 
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 

 
176

 

Fair Value of Derivative Instruments
September 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
 
$
118,202 
 
$
882 
 
$
 
$
(90,582)
 
$
28,502 
Long-term Risk Management Assets
   
56,711 
   
199 
   
   
(30,606)
   
26,304 
Total Assets
   
174,913 
   
1,081 
   
   
(121,188)
   
54,806 
                                 
Current Risk Management Liabilities
   
105,794 
   
1,204 
   
20,465 
   
(94,275)
   
33,188 
Long-term Risk Management Liabilities
   
47,380 
   
287 
   
   
(32,838)
   
14,829 
Total Liabilities
   
153,174 
   
1,491 
   
20,465 
   
(127,113)
   
48,017 
                                 
Total MTM Derivative Contract Net
                             
 
Assets (Liabilities)
 
$
21,739 
 
$
(410)
 
$
(20,465)
 
$
5,925 
 
$
6,789 
                                 
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 

 
177

 


Fair Value of Derivative Instruments
September 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
 
$
242,904 
 
$
1,827 
 
$
 
$
(200,027)
 
$
44,704 
Long-term Risk Management Assets
   
117,272 
   
410 
   
   
(63,355)
   
54,327 
Total Assets
   
360,176 
   
2,237 
   
   
(263,382)
   
99,031 
                                 
Current Risk Management Liabilities
   
231,792 
   
2,477 
   
   
(207,611)
   
26,658 
Long-term Risk Management Liabilities
   
96,861 
   
591 
   
   
(67,939)
   
29,513 
Total Liabilities
   
328,653 
   
3,068 
   
   
(275,550)
   
56,171 
                                 
Total MTM Derivative Contract Net
                             
 
Assets (Liabilities)
 
$
31,523 
 
$
(831)
 
$
 
$
12,168 
 
$
42,860 
                                 
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 

 
178

 


Fair Value of Derivative Instruments
September 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
 
$
4,868 
 
$
54 
 
$
 
$
(4,377)
 
$
545 
Long-term Risk Management Assets
   
300 
   
   
   
(180)
   
124 
Total Assets
   
5,168 
   
58 
   
   
(4,557)
   
669 
                                 
Current Risk Management Liabilities
   
9,435 
   
13 
   
   
(4,377)
   
5,071 
Long-term Risk Management Liabilities
   
1,230 
   
   
   
(184)
   
1,051 
Total Liabilities
   
10,665 
   
18 
   
   
(4,561)
   
6,122 
                                 
Total MTM Derivative Contract Net
                             
 
Assets (Liabilities)
 
$
(5,497)
 
$
40 
 
$
 
$
 
$
(5,453)
                                 
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)

 
179

 


Fair Value of Derivative Instruments
September 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
 
$
7,888 
 
$
51 
 
$
 
$
(7,234)
 
$
705 
Long-term Risk Management Assets
   
467 
   
   
   
(293)
   
178 
Total Assets
   
8,355 
   
55 
   
   
(7,527)
   
883 
                               
Current Risk Management Liabilities
   
11,369 
   
12 
   
   
(7,233)
   
4,148 
Long-term Risk Management Liabilities
   
425 
   
   
   
(297)
   
134 
Total Liabilities
   
11,794 
   
18 
   
   
(7,530)
   
4,282 
                               
Total MTM Derivative Contract Net
                             
 
Assets (Liabilities)
 
$
(3,439)
 
$
37 
 
$
 
$
 
$
(3,399)
                               
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 
 
$
 
$
 
$
(5,885)
 
$
445 
Long-term Risk Management Assets
   
818 
   
   
   
(536)
   
282 
Total Assets
   
7,145 
   
   
   
(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.

 
180

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

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 2012
 
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
       
(in thousands)
Electric Generation, Transmission and
                             
 
Distribution Revenues
 
$
 378 
 
$
 3,814 
 
$
 87 
 
$
 71 
 
$
 174 
Sales to AEP Affiliates
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
Fuel and Other Consumables Used for
                             
 
Electric Generation
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
Regulatory Assets (a)
   
 (138)
   
 (1,213)
   
 3,000 
   
 598 
   
 115 
Regulatory Liabilities (a)
   
 (1,672)
   
 (5,267)
   
 (6,788)
   
 2 
   
 11 
Total Gain (Loss) on Risk Management
                             
 
Contracts
 
$
 (1,432)
 
$
 (2,666)
 
$
 (3,701)
 
$
 671 
 
$
 300 
                                   
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 2011
 
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
       
(in thousands)
Electric Generation, Transmission and
                             
 
Distribution Revenues
 
$
 960 
 
$
 3,094 
 
$
 4,652 
 
$
 (530)
 
$
 (186)
Sales to AEP Affiliates
   
 103 
   
 58 
   
 126 
   
 2 
   
 2 
Fuel and Other Consumables Used for
                             
 
Electric Generation
   
 - 
   
 - 
   
 (2)
   
 - 
   
 - 
Regulatory Assets (a)
   
 139 
   
 71 
   
 (2,846)
   
 (264)
   
 (219)
Regulatory Liabilities (a)
   
 (1,058)
   
 (2,566)
   
 26 
   
 1,930 
   
 174 
Total Gain (Loss) on Risk Management
                             
 
Contracts
 
$
 144 
 
$
 657 
 
$
 1,956 
 
$
 1,138 
 
$
 (229)
                                   

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 2012
 
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
     
(in thousands)
Electric Generation, Transmission and
                             
 
Distribution Revenues
 
$
 (548)
 
$
 9,206 
 
$
 11,118 
 
$
 231 
 
$
 426 
Sales to AEP Affiliates
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
Fuel and Other Consumables Used for
                             
 
Electric Generation
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
Regulatory Assets (a)
   
 (6,133)
   
 (7,228)
   
 (9,026)
   
 (5,360)
   
 (6,977)
Regulatory Liabilities (a)
   
 8,166 
   
 1,851 
   
 390 
   
 3 
   
 6 
Total Gain (Loss) on Risk Management
                             
 
Contracts
 
$
 1,485 
 
$
 3,829 
 
$
 2,482 
 
$
 (5,126)
 
$
 (6,545)
 
 
181

 
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 2011
 
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
     
(in thousands)
Electric Generation, Transmission and
                             
 
Distribution Revenues
 
$
 3,659 
 
$
 12,211 
 
$
 26,806 
 
$
 128 
 
$
 340 
Sales to AEP Affiliates
   
 136 
   
 81 
   
 171 
   
 2 
   
 2 
Fuel and Other Consumables Used for
                             
 
Electric Generation
   
 - 
   
 - 
   
 (2)
   
 - 
   
 - 
Regulatory Assets (a)
   
 373 
   
 186 
   
 (7,028)
   
 285 
   
 2,975 
Regulatory Liabilities (a)
   
 9,827 
   
 (4,230)
   
 (105)
   
 2,509 
   
 58 
Total Gain (Loss) on Risk Management
                             
 
Contracts
 
$
 13,995 
 
$
 8,248 
 
$
 19,842 
 
$
 2,924 
 
$
 3,375 
                                 
(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.”

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 nine months ended September 30, 2012 and 2011, the Registrant Subsidiaries did not designate any fair value hedging strategies.
 
182

 
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 nine months ended September 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 nine months ended September 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 nine months ended September 30, 2012, I&M and SWEPCo designated interest rate derivatives as cash flow hedges.  During the three and nine months ended September 30, 2011, I&M and SWEPCo designated interest rate derivatives as cash flow hedges.  During the nine months ended September 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 nine months ended September 30, 2012 and 2011, SWEPCo designated foreign currency derivatives as cash flow hedges.

During the three and nine months ended September 30, 2012 and 2011, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.
 
183

 
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 nine months ended September 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 September 30, 2012
                                     
Commodity Contracts
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
   
(in thousands)
Balance in AOCI as of June 30, 2012
 
$
 (1,820)
 
$
 (1,246)
 
$
 (2,639)
 
$
 (102)
 
$
 (97)
Changes in Fair Value Recognized in AOCI
   
 1,302 
   
 887 
   
 1,915 
   
 126 
   
 123 
Amount of (Gain) or Loss Reclassified
                             
 
from AOCI to Statement of Income/within
                             
 
Balance Sheet:
                             
   
Electric Generation, Transmission, and
                             
     
Distribution Revenues
   
 (4)
   
 (10)
   
 (23)
   
 - 
   
 - 
   
Fuel and Other Consumables Used for
                             
     
Electric Generation
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
   
Purchased Electricity for Resale
   
 35 
   
 88 
   
 221 
   
 - 
   
 - 
   
Other Operation Expense
   
 (4)
   
 (1)
   
 (6)
   
 - 
   
 1 
   
Maintenance Expense
   
 12 
   
 4 
   
 7 
   
 5 
   
 4 
   
Property, Plant and Equipment
   
 3 
   
 1 
   
 1 
   
 5 
   
 3 
   
Regulatory Assets (a)
   
 114 
   
 20 
   
 - 
   
 - 
   
 - 
   
Regulatory Liabilities (a)
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
Balance in AOCI as of September 30, 2012
 
$
 (362)
 
$
 (257)
 
$
 (524)
 
$
 34 
 
$
 34 
                                     
Interest Rate and
                             
Foreign Currency Contracts
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
         
(in thousands)
Balance in AOCI as of June 30, 2012
 
$
 1,562 
 
$
 (19,015)
 
$
 8,774 
 
$
 6,839 
 
$
 (16,806)
Changes in Fair Value Recognized in AOCI
   
 - 
   
 (1,542)
   
 1 
   
 1 
   
 (1)
Amount of (Gain) or Loss Reclassified
                             
 
from AOCI to Statement of Income/within
                             
 
Balance Sheet:
                             
   
Other Operation Expense
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
   
Depreciation and Amortization
                             
     
Expense
   
 - 
   
 - 
   
 1 
   
 - 
   
 - 
   
Interest Expense
   
 261 
   
 149 
   
 (341)
   
 (190)
   
 567 
Balance in AOCI as of September 30, 2012
 
$
 1,823 
 
$
 (20,408)
 
$
 8,435 
 
$
 6,650 
 
$
 (16,240)
                                     
Total Contracts
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
         
(in thousands)
Balance in AOCI as of June 30, 2012
 
$
 (258)
 
$
 (20,261)
 
$
 6,135 
 
$
 6,737 
 
$
 (16,903)
Changes in Fair Value Recognized in AOCI
   
 1,302 
   
 (655)
   
 1,916 
   
 127 
   
 122 
Amount of (Gain) or Loss Reclassified
                             
 
from AOCI to Statement of Income/within
                             
 
Balance Sheet:
                             
   
Electric Generation, Transmission, and
                             
     
Distribution Revenues
   
 (4)
   
 (10)
   
 (23)
   
 - 
   
 - 
   
Fuel and Other Consumables Used for
                             
     
Electric Generation
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
   
Purchased Electricity for Resale
   
 35 
   
 88 
   
 221 
   
 - 
   
 - 
   
Other Operation Expense
   
 (4)
   
 (1)
   
 (6)
   
 - 
   
 1 
   
Maintenance Expense
   
 12 
   
 4 
   
 7 
   
 5 
   
 4 
   
Depreciation and Amortization
                             
     
Expense
   
 - 
   
 - 
   
 1 
   
 - 
   
 - 
   
Interest Expense
   
 261 
   
 149 
   
 (341)
   
 (190)
   
 567 
   
Property, Plant and Equipment
   
 3 
   
 1 
   
 1 
   
 5 
   
 3 
   
Regulatory Assets (a)
   
 114 
   
 20 
   
 - 
   
 - 
   
 - 
   
Regulatory Liabilities (a)
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
Balance in AOCI as of September 30, 2012
 
$
 1,461 
 
$
 (20,665)
 
$
 7,911 
 
$
 6,684 
 
$
 (16,206)

 
184

 


Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended September 30, 2011
 
Commodity Contracts
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
   
(in thousands)
Balance in AOCI as of June 30, 2011
 
$
 669 
 
$
 378 
 
$
 837 
 
$
 140 
 
$
 132 
Changes in Fair Value Recognized in AOCI
   
 (646)
   
 (332)
   
 (765)
   
 (162)
   
 (148)
Amount of (Gain) or Loss Reclassified
                             
 
from AOCI to Statement of Income/within
                             
 
Balance Sheet:
                             
   
Electric Generation, Transmission, and
                             
     
Distribution Revenues
   
 84 
   
 167 
   
 461 
   
 - 
   
 - 
   
Fuel and Other Consumables Used for
                             
     
Electric Generation
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
   
Purchased Electricity for Resale
   
 (70)
   
 (148)
   
 (402)
   
 - 
   
 - 
   
Other Operation Expense
   
 (32)
   
 (22)
   
 (50)
   
 (28)
   
 (28)
   
Maintenance Expense
   
 (51)
   
 (21)
   
 (46)
   
 (20)
   
 (21)
   
Property, Plant and Equipment
   
 (51)
   
 (28)
   
 (63)
   
 (32)
   
 (27)
   
Regulatory Assets (a)
   
 53 
   
 5 
   
 - 
   
 - 
   
 - 
   
Regulatory Liabilities (a)
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
Balance in AOCI as of September 30, 2011
 
$
 (44)
 
$
 (1)
 
$
 (28)
 
$
 (102)
 
$
 (92)
                                     
Interest Rate and
                             
Foreign Currency Contracts
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
         
(in thousands)
Balance in AOCI as of June 30, 2011
 
$
 486 
 
$
 (8,004)
 
$
 10,133 
 
$
 7,598 
 
$
 (3,057)
Changes in Fair Value Recognized in AOCI
   
 - 
   
 (4,764)
   
 - 
   
 - 
   
 (10,896)
Amount of (Gain) or Loss Reclassified
                             
 
from AOCI to Statement of Income/within
                             
 
Balance Sheet:
                             
   
Other Operation Expense
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
   
Depreciation and Amortization
                             
     
Expense
   
 - 
   
 - 
   
 1 
   
 - 
   
 - 
   
Interest Expense
   
 269 
   
 252 
   
 (340)
   
 (190)
   
 207 
Balance in AOCI as of September 30, 2011
 
$
 755 
 
$
 (12,516)
 
$
 9,794 
 
$
 7,408 
 
$
 (13,746)
                                     
Total Contracts
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
         
(in thousands)
Balance in AOCI as of June 30, 2011
 
$
 1,155 
 
$
 (7,626)
 
$
 10,970 
 
$
 7,738 
 
$
 (2,925)
Changes in Fair Value Recognized in AOCI
   
 (646)
   
 (5,096)
   
 (765)
   
 (162)
   
 (11,044)
Amount of (Gain) or Loss Reclassified
                             
 
from AOCI to Statement of Income/within
                             
 
Balance Sheet:
                             
   
Electric Generation, Transmission, and
                             
     
Distribution Revenues
   
 84 
   
 167 
   
 461 
   
 - 
   
 - 
   
Fuel and Other Consumables Used for
                             
     
Electric Generation
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
   
Purchased Electricity for Resale
   
 (70)
   
 (148)
   
 (402)
   
 - 
   
 - 
   
Other Operation Expense
   
 (32)
   
 (22)
   
 (50)
   
 (28)
   
 (28)
   
Maintenance Expense
   
 (51)
   
 (21)
   
 (46)
   
 (20)
   
 (21)
   
Depreciation and Amortization
                             
     
Expense
   
 - 
   
 - 
   
 1 
   
 - 
   
 - 
   
Interest Expense
   
 269 
   
 252 
   
 (340)
   
 (190)
   
 207 
   
Property, Plant and Equipment
   
 (51)
   
 (28)
   
 (63)
   
 (32)
   
 (27)
   
Regulatory Assets (a)
   
 53 
   
 5 
   
 - 
   
 - 
   
 - 
   
Regulatory Liabilities (a)
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
Balance in AOCI as of September 30, 2011
 
$
 711 
 
$
 (12,517)
 
$
 9,766 
 
$
 7,306 
 
$
 (13,838)

 
185

 


Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Nine Months Ended September 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
   
 (946)
   
 (741)
   
 (1,487)
   
 110 
   
 106 
Amount of (Gain) or Loss Reclassified
                             
 
from AOCI to Statement of Income/within
                             
 
Balance Sheet:
                             
   
Electric Generation, Transmission, and
                             
     
Distribution Revenues
   
 (7)
   
 (19)
   
 (47)
   
 - 
   
 - 
   
Fuel and Other Consumables Used for
                             
     
Electric Generation
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
   
Purchased Electricity for Resale
   
 411 
   
 1,074 
   
 2,806 
   
 - 
   
 - 
   
Other Operation Expense
   
 (20)
   
 (11)
   
 (30)
   
 (11)
   
 (8)
   
Maintenance Expense
   
 3 
   
 - 
   
 (3)
   
 3 
   
 1 
   
Property, Plant and Equipment
   
 (9)
   
 (6)
   
 (15)
   
 1 
   
 (3)
   
Regulatory Assets (a)
   
 1,515 
   
 265 
   
 - 
   
 - 
   
 - 
   
Regulatory Liabilities (a)
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
Balance in AOCI as of September 30, 2012
 
$
 (362)
 
$
 (257)
 
$
 (524)
 
$
 34 
 
$
 34 
                                     
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
   
 - 
   
 (6,390)
   
 1 
   
 1 
   
 (2,778)
Amount of (Gain) or Loss Reclassified
                             
 
from AOCI to Statement of Income/within
                             
 
Balance Sheet:
                             
   
Other Operation Expense
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
   
Depreciation and Amortization
                             
     
Expense
   
 - 
   
 - 
   
 3 
   
 - 
   
 - 
   
Interest Expense
   
 799 
   
 447 
   
 (1,023)
   
 (569)
   
 2,000 
Balance in AOCI as of September 30, 2012
 
$
 1,823 
 
$
 (20,408)
 
$
 8,435 
 
$
 6,650 
 
$
 (16,240)
                                     
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
   
 (946)
   
 (7,131)
   
 (1,486)
   
 111 
   
 (2,672)
Amount of (Gain) or Loss Reclassified
                             
 
from AOCI to Statement of Income/within
                             
 
Balance Sheet:
                             
   
Electric Generation, Transmission, and
                             
     
Distribution Revenues
   
 (7)
   
 (19)
   
 (47)
   
 - 
   
 - 
   
Fuel and Other Consumables Used for
                             
     
Electric Generation
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
   
Purchased Electricity for Resale
   
 411 
   
 1,074 
   
 2,806 
   
 - 
   
 - 
   
Other Operation Expense
   
 (20)
   
 (11)
   
 (30)
   
 (11)
   
 (8)
   
Maintenance Expense
   
 3 
   
 - 
   
 (3)
   
 3 
   
 1 
   
Depreciation and Amortization
                             
     
Expense
   
 - 
   
 - 
   
 3 
   
 - 
   
 - 
   
Interest Expense
   
 799 
   
 447 
   
 (1,023)
   
 (569)
   
 2,000 
   
Property, Plant and Equipment
   
 (9)
   
 (6)
   
 (15)
   
 1 
   
 (3)
   
Regulatory Assets (a)
   
 1,515 
   
 265 
   
 - 
   
 - 
   
 - 
   
Regulatory Liabilities (a)
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
Balance in AOCI as of September 30, 2012
 
$
 1,461 
 
$
 (20,665)
 
$
 7,911 
 
$
 6,684 
 
$
 (16,206)

 
186

 


Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Nine Months Ended September 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
   
 (523)
   
 (279)
   
 (622)
   
 18 
   
 20 
Amount of (Gain) or Loss Reclassified
                             
 
from AOCI to Statement of Income/within
                             
 
Balance Sheet:
                             
   
Electric Generation, Transmission, and
                             
     
Distribution Revenues
   
 255 
   
 553 
   
 1,495 
   
 - 
   
 - 
   
Fuel and Other Consumables Used for
                             
     
Electric Generation
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
   
Purchased Electricity for Resale
   
 (24)
   
 (46)
   
 (127)
   
 - 
   
 - 
   
Other Operation Expense
   
 (76)
   
 (59)
   
 (133)
   
 (75)
   
 (74)
   
Maintenance Expense
   
 (141)
   
 (53)
   
 (116)
   
 (49)
   
 (53)
   
Property, Plant and Equipment
   
 (131)
   
 (67)
   
 (161)
   
 (84)
   
 (67)
   
Regulatory Assets (a)
   
 869 
   
 128 
   
 - 
   
 - 
   
 - 
   
Regulatory Liabilities (a)
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
Balance in AOCI as of September 30, 2011
 
$
 (44)
 
$
 (1)
 
$
 (28)
 
$
 (102)
 
$
 (92)
                                     
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)
   
 (4,764)
   
 - 
   
 (476)
   
 (10,095)
Amount of (Gain) or Loss Reclassified
                             
 
from AOCI to Statement of Income/within
                             
 
Balance Sheet:
                             
   
Other Operation Expense
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
   
Depreciation and Amortization
                             
     
Expense
   
 - 
   
 - 
   
 3 
   
 - 
   
 - 
   
Interest Expense
   
 911 
   
 755 
   
 (1,022)
   
 (522)
   
 621 
Balance in AOCI as of September 30, 2011
 
$
 755 
 
$
 (12,516)
 
$
 9,794 
 
$
 7,408 
 
$
 (13,746)
                                     
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
   
 (896)
   
 (5,043)
   
 (622)
   
 (458)
   
 (10,075)
Amount of (Gain) or Loss Reclassified
                             
 
from AOCI to Statement of Income/within
                             
 
Balance Sheet:
                             
   
Electric Generation, Transmission, and
                             
     
Distribution Revenues
   
 255 
   
 553 
   
 1,495 
   
 - 
   
 - 
   
Fuel and Other Consumables Used for
                             
     
Electric Generation
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
   
Purchased Electricity for Resale
   
 (24)
   
 (46)
   
 (127)
   
 - 
   
 - 
   
Other Operation Expense
   
 (76)
   
 (59)
   
 (133)
   
 (75)
   
 (74)
   
Maintenance Expense
   
 (141)
   
 (53)
   
 (116)
   
 (49)
   
 (53)
   
Depreciation and Amortization
                             
     
Expense
   
 - 
   
 - 
   
 3 
   
 - 
   
 - 
   
Interest Expense
   
 911 
   
 755 
   
 (1,022)
   
 (522)
   
 621 
   
Property, Plant and Equipment
   
 (131)
   
 (67)
   
 (161)
   
 (84)
   
 (67)
   
Regulatory Assets (a)
   
 869 
   
 128 
   
 - 
   
 - 
   
 - 
   
Regulatory Liabilities (a)
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
Balance in AOCI as of September 30, 2011
 
$
 711 
 
$
 (12,517)
 
$
 9,766 
 
$
 7,306 
 
$
 (13,838)
                                     
(a)
 
Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.

 
187

 
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2012 and December 31, 2011 were:
Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
September 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
 
$
 925 
 
$
 - 
 
$
 1,503 
 
$
 - 
 
$
 (362)
 
$
 1,823 
I&M
   
 622 
   
 - 
   
 1,032 
   
 20,465 
   
 (257)
   
 (20,408)
OPCo
   
 1,289 
   
 - 
   
 2,120 
   
 - 
   
 (524)
   
 8,435 
PSO
   
 46 
   
 - 
   
 6 
   
 - 
   
 34 
   
 6,650 
SWEPCo
   
 43 
   
 - 
   
 6 
   
 - 
   
 34 
   
 (16,240)

     
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
 
$
 (278)
 
$
 (1,013)
   
 20 
I&M
   
 (202)
   
 (1,316)
   
 20 
OPCo
   
 (405)
   
 1,359 
   
 20 
PSO
   
 36 
   
 759 
   
 15 
SWEPCo
   
 34 
   
 (2,369)
   
 15 

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.

 
188

 
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 September 30, 2012 and December 31, 2011:

     
September 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
 
$
 2,155 
 
$
 4,301 
 
$
 4,301 
I&M
   
 1,481 
   
 2,956 
   
 2,956 
OPCo
   
 3,042 
   
 6,070 
   
 6,070 
PSO
   
 - 
   
 1,288 
   
 885 
SWEPCo
   
 - 
   
 1,517 
   
 1,042 


     
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 September 30, 2012 and December 31, 2011, the Registrant Subsidiaries were not required to post any collateral.
 
189

 
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 September 30, 2012 and December 31, 2011:

     
September 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
 
$
 64,466 
 
$
 76 
 
$
 33,019 
I&M
   
 64,767 
   
 52 
   
 43,156 
OPCo
   
 90,977 
   
 107 
   
 46,597 
PSO
   
 26 
   
 - 
   
 16 
SWEPCo
   
 30 
   
 - 
   
 19 
                     
     
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 

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.  The AEP System’s market risk oversight staff independently monitors its valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures.  The CORC consists of AEPSC’s Chief Operation Officer, Chief Financial Officer, Senior Vice President of Commercial Operations and Chief Risk Officer.
 
190

 
For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which are non-binding in nature, but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, the quoted bid and ask prices are averaged.  In certain circumstances, a broker quote may be discarded if it is a clear outlier.  Management uses a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Long-dated and illiquid complex or structured transactions, FTRs and counterparty credit risk 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.  A significant portion of the Level 3 instruments 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 September 30, 2012 and December 31, 2011 are summarized in the following table:

   
September 30, 2012
 
December 31, 2011
Company
 
Book Value
 
Fair Value
 
Book Value
 
Fair Value
   
(in thousands)
APCo
 
$
 3,702,283 
 
$
 4,597,740 
 
$
 3,726,251 
 
$
 4,431,912 
I&M
   
 2,109,630 
   
 2,431,912 
   
 2,057,675 
   
 2,339,344 
OPCo
   
 3,860,242 
   
 4,589,998 
   
 4,054,148 
   
 4,665,739 
PSO
   
 949,884 
   
 1,187,155 
   
 947,364 
   
 1,123,306 
SWEPCo
   
 2,046,139 
   
 2,424,311 
   
 1,728,637 
   
 2,019,094 

 
191

 
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 September 30, 2012 and December 31, 2011:

     
September 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
 
$
 12,945 
 
$
 - 
 
$
 - 
 
$
 18,229 
 
$
 - 
 
$
 - 
Fixed Income Securities:
                                   
 
United States Government
   
 693,127 
   
 107,721 
   
 (612)
   
 543,506 
   
 60,946 
   
 (547)
 
Corporate Debt
   
 35,798 
   
 5,531 
   
 (1,435)
   
 53,979 
   
 4,932 
   
 (1,536)
 
State and Local Government
   
 226,142 
   
 1,301 
   
 (660)
   
 329,986 
   
 (430)
   
 (2,236)
 
  Subtotal Fixed Income Securities
 
 955,067 
   
 114,553 
   
 (2,707)
   
 927,471 
   
 65,448 
   
 (4,319)
Equity Securities - Domestic
   
 731,679 
   
 291,224 
   
 (77,662)
   
 646,032 
   
 214,748 
   
 (79,536)
Spent Nuclear Fuel and
                                   
 
Decommissioning Trusts
 
$
 1,699,691 
 
$
 405,777 
 
$
 (80,369)
 
$
 1,591,732 
 
$
 280,196 
 
$
 (83,855)

 
192

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

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2012 
 
2011 
 
2012 
 
2011 
 
(in thousands)
Proceeds from Investment Sales
$
 181,988 
 
$
 361,001 
 
$
 698,567 
 
$
 825,689 
Purchases of Investments
 
 199,150 
   
 378,607 
   
 744,131 
   
 870,769 
Gross Realized Gains on Investment Sales
 
 2,046 
   
 17,256 
   
 6,978 
   
 29,661 
Gross Realized Losses on Investment Sales
 
 924 
   
 11,313 
   
 3,143 
   
 20,603 

The adjusted cost of fixed income securities was $840 million and $862 million as of September 30, 2012 and December 31, 2011, respectively.  The adjusted cost of equity securities was $441 million and $431 million as of September 30, 2012 and December 31, 2011, respectively.

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

 
Fair Value of
 
 
Fixed Income
 
 
Securities
 
 
(in thousands)
 
Within 1 year
$ 136,610  
1 year – 5 years
  356,630  
5 years – 10 years
  265,125  
After 10 years
  196,702  
Total
$ 955,067  

 
193

 
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 September 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
September 30, 2012
APCo
                 
   
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
                               
Risk Management Assets
                           
Risk Management Commodity Contracts (a) (f)
$
 4,301 
 
$
 219,033 
 
$
 23,357 
 
$
 (178,608)
 
$
 68,083 
Cash Flow Hedges:
                           
 
Commodity Hedges (a)
 
 - 
   
 1,306 
   
 289 
   
 (670)
   
 925 
De-designated Risk Management Contracts (b)
 
 - 
   
 - 
   
 - 
   
 590 
   
 590 
Total Risk Management Assets
$
 4,301 
 
$
 220,339 
 
$
 23,646 
 
$
 (178,688)
 
$
 69,598 
                               
Liabilities:
                           
                               
Risk Management Liabilities
                           
Risk Management Commodity Contracts (a) (f)
$
 1,931 
 
$
 209,732 
 
$
 12,606 
 
$
 (186,641)
 
$
 37,628 
Cash Flow Hedges:
                           
 
Commodity Hedges (a)
 
 - 
   
 2,173 
   
 - 
   
 (670)
   
 1,503 
Total Risk Management Liabilities
$
 1,931 
 
$
 211,905 
 
$
 12,606 
 
$
 (187,311)
 
$
 39,131 

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 

 
194

 


Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2012
I&M
                 
     
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
                                 
Risk Management Assets
                           
Risk Management Commodity Contracts (a) (f)
$
 2,955 
 
$
 154,581 
 
$
 16,051 
 
$
 (119,809)
 
$
 53,778 
Cash Flow Hedges:
                           
 
Commodity Hedges (a)
 
 - 
   
 880 
   
 198 
   
 (456)
   
 622 
De-designated Risk Management Contracts (b)
 
 - 
   
 - 
   
 - 
   
 406 
   
 406 
Total Risk Management Assets
 
 2,955 
   
 155,461 
   
 16,249 
   
 (119,859)
   
 54,806 
                                 
Spent Nuclear Fuel and Decommissioning Trusts
                           
Cash and Cash Equivalents (d)
 
 - 
   
 4,995 
   
 - 
   
 7,950 
   
 12,945 
Fixed Income Securities:
                           
 
United States Government
 
 - 
   
 693,127 
   
 - 
   
 - 
   
 693,127 
 
Corporate Debt
 
 - 
   
 35,798 
   
 - 
   
 - 
   
 35,798 
 
State and Local Government
 
 - 
   
 226,142 
   
 - 
   
 - 
   
 226,142 
   
Subtotal Fixed Income Securities
 
 - 
   
 955,067 
   
 - 
   
 - 
   
 955,067 
Equity Securities - Domestic (e)
 
 731,679 
   
 - 
   
 - 
   
 - 
   
 731,679 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 731,679 
   
 960,062 
   
 - 
   
 7,950 
   
 1,699,691 
                                 
Total Assets
$
 734,634 
 
$
 1,115,523 
 
$
 16,249 
 
$
 (111,909)
 
$
 1,754,497 
                                 
Liabilities:
                           
                                 
Risk Management Liabilities
                           
Risk Management Commodity Contracts (a) (f)
$
 1,327 
 
$
 141,858 
 
$
 8,663 
 
$
 (125,328)
 
$
 26,520 
Cash Flow Hedges:
                           
 
Commodity Hedges (a)
 
 - 
   
 1,488 
   
 - 
   
 (456)
   
 1,032 
 
Interest Rate/Foreign Currency Hedges
 
 - 
   
 20,465 
   
 - 
   
 - 
   
 20,465 
Total Risk Management Liabilities
$
 1,327 
 
$
 163,811 
 
$
 8,663 
 
$
 (125,784)
 
$
 48,017 

 
195

 
   
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 

 
196

 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
September 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)
 
 6,069 
   
 318,501 
   
 32,962 
   
 (260,623)
   
 96,909 
Cash Flow Hedges:
                           
 
Commodity Hedges (a)
 
 - 
   
 1,824 
   
 407 
   
 (942)
   
 1,289 
De-designated Risk Management Contracts (b)
 
 - 
   
 - 
   
 - 
   
 833 
   
 833 
Total Risk Management Assets
 
 6,069 
   
 320,325 
   
 33,369 
   
 (260,732)
   
 99,031 
                               
Total Assets
$
 6,069 
 
$
 320,351 
 
$
 33,369 
 
$
 (260,693)
 
$
 99,096 
                               
Liabilities:
                           
                               
Risk Management Liabilities
                           
Risk Management Commodity Contracts (a) (f)
$
 2,726 
 
$
 305,493 
 
$
 17,790 
 
$
 (271,958)
 
$
 54,051 
Cash Flow Hedges:
                           
 
Commodity Hedges (a)
 
 - 
   
 3,062 
   
 - 
   
 (942)
   
 2,120 
Total Risk Management Liabilities
$
 2,726 
 
$
 308,555 
 
$
 17,790 
 
$
 (272,900)
 
$
 56,171 

 
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 

 
197

 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
September 30, 2012
PSO
                 
   
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
                               
Risk Management Assets
                           
Risk Management Commodity Contracts (a) (f)
$
 8 
 
$
 5,126 
 
$
 - 
 
$
 (4,511)
 
$
 623 
Cash Flow Hedges:
                           
 
Commodity Hedges (a)
 
 - 
   
 58 
   
 - 
   
 (12)
   
 46 
Total Risk Management Assets
$
 8 
 
$
 5,184 
 
$
 - 
 
$
 (4,523)
 
$
 669 
                               
Liabilities:
                           
                               
Risk Management Liabilities
                           
Risk Management Commodity Contracts (a) (f)
$
 6 
 
$
 10,625 
 
$
 - 
 
$
 (4,515)
 
$
 6,116 
Cash Flow Hedges:
                           
 
Commodity Hedges (a)
 
 - 
   
 18 
   
 - 
   
 (12)
   
 6 
Total Risk Management Liabilities
$
 6 
 
$
 10,643 
 
$
 - 
 
$
 (4,527)
 
$
 6,122 

 
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 

 
198

 


Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2012
SWEPCo
                 
   
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
                               
Cash and Cash Equivalents (c)
$
 14,108 
 
$
 - 
 
$
 - 
 
$
 2,518 
 
$
 16,626 
                               
Risk Management Assets
                           
Risk Management Commodity Contracts (a) (f)
 
 9 
   
 8,303 
   
 - 
   
 (7,472)
   
 840 
Cash Flow Hedges:
                           
 
Commodity Hedges (a)
 
 - 
   
 55 
   
 - 
   
 (12)
   
 43 
Total Risk Management Assets
 
 9 
   
 8,358 
   
 - 
   
 (7,484)
   
 883 
                               
Total Assets
$
 14,117 
 
$
 8,358 
 
$
 - 
 
$
 (4,966)
 
$
 17,509 
                               
Liabilities:
                           
                               
Risk Management Liabilities
                           
Risk Management Commodity Contracts (a) (f)
$
 7 
 
$
 11,744 
 
$
 - 
 
$
 (7,475)
 
$
 4,276 
Cash Flow Hedges:
                           
 
Commodity Hedges (a)
 
 - 
   
 18 
   
 - 
   
 (12)
   
 6 
Total Risk Management Liabilities
$
 7 
 
$
 11,762 
 
$
 - 
 
$
 (7,487)
 
$
 4,282 

 
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 nine months ended September 30, 2012 and 2011.

 
199

 
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 September 30, 2012
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
   
(in thousands)
Balance as of June 30, 2012
 
$
 12,864 
 
$
 9,049 
 
$
 18,969 
 
$
 - 
 
$
 - 
Realized Gain (Loss) Included in Net Income
                             
 
(or Changes in Net Assets) (a) (b)
   
 (3,540)
   
 (2,440)
   
 (5,024)
   
 - 
   
 - 
Unrealized Gain (Loss) Included in Net
                             
 
Income (or Changes in Net Assets) Relating
                             
 
to Assets Still Held at the Reporting Date (a)
   
 - 
   
 - 
   
 (1,030)
   
 - 
   
 - 
Realized and Unrealized Gains (Losses)
                             
 
Included in Other Comprehensive Income
   
 403 
   
 277 
   
 571 
   
 - 
   
 - 
Purchases, Issuances and Settlements (c)
   
 929 
   
 635 
   
 1,299 
   
 - 
   
 - 
Transfers into Level 3 (d) (f)
   
 654 
   
 460 
   
 964 
   
 - 
   
 - 
Transfers out of Level 3 (e) (f)
   
 (287)
   
 (202)
   
 (423)
   
 - 
   
 - 
Changes in Fair Value Allocated to Regulated
                             
 
Jurisdictions (g)
   
 17 
   
 (193)
   
 253 
   
 - 
   
 - 
Balance as of September 30, 2012
 
$
 11,040 
 
$
 7,586 
 
$
 15,579 
 
$
 - 
 
$
 - 

Three Months Ended September 30, 2011
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
   
(in thousands)
Balance as of June 30, 2011
 
$
 5,321 
 
$
 3,150 
 
$
 6,759 
 
$
 - 
 
$
 - 
Realized Gain (Loss) Included in Net Income
                             
 
(or Changes in Net Assets) (a) (b)
   
 (4,553)
   
 (2,904)
   
 (6,138)
   
 - 
   
 - 
Unrealized Gain (Loss) Included in Net
                             
 
Income (or Changes in Net Assets) Relating
                             
 
to Assets Still Held at the Reporting Date (a)
   
 - 
   
 - 
   
 (939)
   
 - 
   
 - 
Realized and Unrealized Gains (Losses)
                             
 
Included in Other Comprehensive Income
   
 (7)
   
 (7)
   
 (13)
   
 - 
   
 - 
Purchases, Issuances and Settlements (c)
   
 358 
   
 297 
   
 599 
   
 - 
   
 - 
Transfers into Level 3 (d) (f)
   
 - 
   
 - 
   
 - 
   
 - 
   
 - 
Transfers out of Level 3 (e) (f)
   
 (259)
   
 (154)
   
 (330)
   
 - 
   
 - 
Changes in Fair Value Allocated to Regulated
                             
 
Jurisdictions (g)
   
 (91)
   
 112 
   
 1,103 
   
 - 
   
 - 
Balance as of September 30, 2011
 
$
 769 
 
$
 494 
 
$
 1,041 
 
$
 - 
 
$
 - 

Nine Months Ended September 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)
   
 (5,108)
   
 (3,488)
   
 (7,316)
   
 - 
   
 - 
Unrealized Gain (Loss) Included in Net
                             
 
Income (or Changes in Net Assets) Relating
                             
 
to Assets Still Held at the Reporting Date (a)
   
 - 
   
 - 
   
 4,973 
   
 - 
   
 - 
Realized and Unrealized Gains (Losses)
                             
 
Included in Other Comprehensive Income
   
 312 
   
 211 
   
 435 
   
 - 
   
 - 
Purchases, Issuances and Settlements (c)
   
 10,605 
   
 7,325 
   
 15,375 
   
 - 
   
 - 
Transfers into Level 3 (d) (f)
   
 4,142 
   
 2,749 
   
 5,789 
   
 - 
   
 - 
Transfers out of Level 3 (e) (f)
   
 (4,910)
   
 (3,193)
   
 (6,733)
   
 - 
   
 - 
Changes in Fair Value Allocated to Regulated
                             
 
Jurisdictions (g)
   
 4,028 
   
 2,719 
   
 390 
   
 - 
   
 - 
Balance as of September 30, 2012
 
$
 11,040 
 
$
 7,586 
 
$
 15,579 
 
$
 - 
 
$
 - 

 
200

 
Nine Months Ended September 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)
   
 (2,373)
   
 (1,401)
   
 (3,007)
   
 - 
   
 - 
Unrealized Gain (Loss) Included in Net
                             
 
Income (or Changes in Net Assets) Relating
                             
 
to Assets Still Held at the Reporting Date (a)
   
 - 
   
 - 
   
 1,947 
   
 - 
   
 - 
Realized and Unrealized Gains (Losses)
                             
 
Included in Other Comprehensive Income
   
 (45)
   
 (29)
   
 (61)
   
 - 
   
 - 
Purchases, Issuances and Settlements (c)
   
 2,835 
   
 1,656 
   
 3,567 
   
 - 
   
 - 
Transfers into Level 3 (d) (f)
   
 1,299 
   
 764 
   
 1,638 
   
 - 
   
 - 
Transfers out of Level 3 (e) (f)
   
 (3,057)
   
 (1,834)
   
 (3,908)
   
 - 
   
 - 
Changes in Fair Value Allocated to Regulated
                             
 
Jurisdictions (g)
   
 (3,021)
   
 (1,770)
   
 (5,718)
   
 (1)
   
 (2)
Balance as of September 30, 2011
 
$
 769 
 
$
 494 
 
$
 1,041 
 
$
 - 
 
$
 - 

(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.

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

APCo
 
Fair Value
 
Valuation
 
Significant
 
Forward Price Range
 
Assets
 
Liabilities
Technique
Unobservable Input (a)
 
Low
 
High
   
(in thousands)
                   
Energy Contracts
 
$
 21,300 
 
$
 10,451 
 
Discounted Cash Flow
 
Forward Market Price
 
$
 10.45 
 
$
 63.25 
FTRs
   
 2,346 
   
 2,155 
 
Discounted Cash Flow
 
Forward Market Price
   
 (3.81)
   
 9.92 
Total
 
$
 23,646 
 
$
 12,606 
                   

I&M
 
Fair Value
 
Valuation
 
Significant
 
Forward Price Range
 
Assets
 
Liabilities
Technique
Unobservable Input (a)
 
Low
 
High
   
(in thousands)
                   
Energy Contracts
 
$
 14,637 
 
$
 7,182 
 
Discounted Cash Flow
 
Forward Market Price
 
$
 10.45 
 
$
 63.25 
FTRs
   
 1,612 
   
 1,481 
 
Discounted Cash Flow
 
Forward Market Price
   
 (3.81)
   
 9.92 
Total
 
$
 16,249 
 
$
 8,663 
                   

OPCo
 
Fair Value
 
Valuation
 
Significant
 
Forward Price Range
 
Assets
 
Liabilities
Technique
Unobservable Input (a)
 
Low
 
High
   
(in thousands)
                   
Energy Contracts
 
$
 30,058 
 
$
 14,748 
 
Discounted Cash Flow
 
Forward Market Price
 
$
 10.45 
 
$
 63.25 
FTRs
   
 3,311 
   
 3,042 
 
Discounted Cash Flow
 
Forward Market Price
   
 (3.81)
   
 9.92 
Total
 
$
 33,369 
 
$
 17,790 
                   

(a)
Represents market prices in dollars per MWh.

 
201

 
9.  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 Registrant Subsidiaries' net income, cash flows or financial condition.

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 as of 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 as of September 30, 2012
 
$
 15,010 

State Tax Legislation

During the third quarter of 2012, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds and thus, the West Virginia corporate income tax rate will be reduced from 7.75% to 7.0% in 2013.  The enacted provisions will not have a material impact on the Registrant Subsidiaries’ net income, cash flows or financial condition.
 
202

 
10.  FINANCING ACTIVITIES

Long-term Debt

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

       
Principal
 
Interest
   
Company
 
Type of Debt
 
Amount
 
Rate
 
Due Date
Issuances:
     
(in thousands)
 
(%)
   
APCo
 
Senior Unsecured Notes
 
$
 275,000 
 
Variable
 
2013 
APCo
 
Pollution Control Bonds
   
 65,350 
 
2.25 
 
2016 
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
 
Pollution Control Bonds
   
 65,350 
 
2.00 
 
2012 
APCo
 
Senior Unsecured Notes
   
 250,000 
 
5.65 
 
2012 
APCo
 
Land Note
   
 18 
 
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
   
 15,353 
 
Variable
 
2015 
I&M
 
Notes Payable
   
 17,924 
 
Variable
 
2016 
I&M
 
Notes Payable
   
 12,414 
 
2.12 
 
2016 
I&M
 
Notes Payable
   
 7,552 
 
Variable
 
2016 
I&M
 
Other Long-term Debt
   
 371 
 
6.00 
 
2025 
OPCo
 
Pollution Control Bonds
   
 44,500 
 
4.85 
 
2012 
OPCo
 
Senior Unsecured Notes
   
 150,000 
 
Variable
 
2012 
PSO
 
Notes Payable
   
 130 
 
3.00 
 
2027 
SWEPCo
 
Notes Payable
   
 20,000 
 
7.03 
 
2012 
SWEPCo
 
Notes Payable
   
 1,625 
 
4.58 
 
2032 

In October 2012, I&M retired $29 million of Notes Payable related to DCC Fuel.

As of September 30, 2012, trustees held, on behalf of OPCo, $463 million of its reacquired Pollution Control Bonds.
 
203

 
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, management understands “capital account” to mean the book 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 September 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 nine months ended September 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
 
September 30, 2012
 
Limit
   
(in thousands)
APCo
 
$
 350,153 
 
$
 23,195 
 
$
 168,094 
 
$
 22,692 
 
$
 (94,807)
 
$
 600,000 
I&M
   
 - 
   
 362,733 
   
 - 
   
 208,072 
   
 284,768 
   
 500,000 
OPCo
   
 126,975 
   
 290,356 
   
 47,820 
   
 92,517 
   
 124,606 
   
 600,000 
PSO
   
 - 
   
 177,778 
   
 - 
   
 93,219 
   
 107,459 
   
 300,000 
SWEPCo
   
 227,087 
   
 128,227 
   
 147,338 
   
 62,312 
   
 128,227 
   
 350,000 

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:

   
Nine Months Ended September 30,
   
2012 
 
2011 
Maximum Interest Rate
 
 0.56 
%
 
 0.56 
%
Minimum Interest Rate
 
 0.44 
%
 
 0.06 
%

 
204

 
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 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
   
Nine Months Ended September 30,
 
Nine Months Ended September 30,
Company
 
2012 
 
2011 
2012 
 
2011 
                         
APCo
 
 0.48 
%
 
 0.38 
%
 
 0.48 
%
 
 0.31 
%
I&M
 
 - 
%
 
 0.39 
%
 
 0.47 
%
 
 0.31 
%
OPCo
 
 0.47 
%
 
 0.45 
%
 
 0.50 
%
 
 0.31 
%
PSO
 
 - 
%
 
 0.41 
%
 
 0.47 
%
 
 0.26 
%
SWEPCo
 
 0.53 
%
 
 0.34 
%
 
 0.47 
%
 
 0.33 
%

Short-term Debt
                       
                                 
The Registrant Subsidiaries’ outstanding short-term debt was as follows:
                                 
           
September 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 rate.

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 statements of income.  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 September 30, 2012 and December 31, 2011 was as follows:

     
September 30,
 
December 31,
Company
 
2012 
 
2011 
     
(in thousands)
APCo
 
$
 131,937 
 
$
 121,605 
I&M
   
 116,702 
   
 121,597 
OPCo
   
 322,440 
   
 346,695 
PSO
   
 127,008 
   
 123,172 
SWEPCo
   
 160,802 
   
 140,440 

 
205

 
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:

     
Three Months Ended September 30,
 
Nine Months Ended September 30,
Company
 
2012 
 
2011 
 
2012 
 
2011 
     
(in thousands)
APCo
 
$
 1,703 
 
$
 2,500 
 
$
 5,389 
 
$
 7,314 
I&M
   
 1,674 
   
 1,623 
   
 4,738 
   
 4,758 
OPCo
   
 5,362 
   
 5,585 
   
 15,900 
   
 14,025 
PSO
   
 1,990 
   
 2,081 
   
 5,547 
   
 4,798 
SWEPCo
   
 1,786 
   
 1,850 
   
 4,720 
   
 4,254 

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

     
Three Months Ended September 30,
 
Nine Months Ended September 30,
Company
 
2012 
 
2011 
 
2012 
 
2011 
     
(in thousands)
APCo
 
$
 351,570 
 
$
 307,364 
 
$
 993,975 
 
$
 958,288 
I&M
   
 358,936 
   
 350,108 
   
 1,018,933 
   
 1,016,680 
OPCo
   
 790,115 
   
 956,909 
   
 2,284,749 
   
 2,699,782 
PSO
   
 342,819 
   
 436,339 
   
 919,343 
   
 1,021,967 
SWEPCo
   
 444,461 
   
 475,219 
   
 1,145,182 
   
 1,165,245 

11.  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 in early 2013.  The severance program provides two weeks of base pay for every year of service along with other severance benefits.

The Registrant Subsidiaries recorded charges to expense in 2012 related to the sustainable cost reductions initiative.

     
Expense
 
Incurred for
       
Remaining
     
Allocation from
 
Registrant
       
Balance at
   
    AEPSC
 
Subsidiaries
 
Settled
 
 September 30, 2012
   
(in thousands)
APCo
 
$
 2,076 
 
$
 715 
 
$
 (2,780)
 
$
 11 
I&M
   
 1,231 
   
 277 
   
 (1,480)
   
 28 
OPCo
   
 3,099 
   
 756 
   
 (3,827)
   
 28 
PSO
   
 1,121 
   
 3 
   
 (1,124)
   
 - 
SWEPCo
   
 1,367 
   
 898 
   
 (2,241)
   
 24 

These expenses relate primarily to severance benefits.  They are included primarily in Other Operation on the condensed statements of income and Other Current Liabilities on the condensed balance sheets.  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 net income, cash flows and financial condition.

 
206

 
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

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.  In October 2012, the PUCO issued an order which approved the transfer of OPCo’s generation assets at net book value to AEP Generation Resources, Inc. (AEPGenCo), a nonregulated affiliate in the Generation and Marketing segment.  AEPGenCo will also assume the associated generation liabilities.  Management intends to file an application with the FERC in the fourth quarter of 2012 related to corporate separation.  Prior to corporate separation, OPCo’s results of operations related to generation could be affected by the ability to sell power and capacity at a profit at rates determined by the prevailing market.  If power and capacity are not sold at a profit, it could reduce OPCo’s future net income and cash flows and impact financial condition

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.  Management intends to file an application with the FERC in the fourth quarter of 2012 to terminate the Interconnection Agreement.  It is unknown 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 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.

Based on the interdependent nature of generation activities subject to the Interconnection Agreement, the AEP East companies’ generation assets are evaluated for their accounting recoverability collectively as an asset group.  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 accounting evaluation of the recoverability of the net book values of OPCo’s generation assets. The net book value of the OPCo units that management plans to retire included in the table below in the “Environmental Controls Impact on the Generating Fleet” section and OPCo’s share of the W. C. Beckjord Generating Station was $284 million as of September 30, 2012.  These generating assets are being depreciated through May 2015.

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.
 
207

 
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.

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 September 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.  If natural gas conversion is not completed, the units could be closed sooner than planned.

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 more stringent standards, (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.
 
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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.

In September 2012, based upon an agreement in principle with the Federal EPA, the State of Oklahoma and other parties, PSO filed an environmental compliance plan with the OCC to retire Units 3 and 4 of the Northeastern Station, a total of 930 MWs, in 2026 and 2016, respectively.  See “Oklahoma Environmental Compliance Plan” and “Regional Haze” sections below.

Natural gas prices and pending environmental rules could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of certain coal-fired units.   Management is still evaluating 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 based on 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 under the accounting evaluations, it could materially reduce future net income and cash flows.

Environmental Compliance Applications

Rockport Plant Environmental Controls

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 September 30, 2012, I&M has incurred $24 million, including AFUDC.  If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

In July 2012, certain intervenors filed testimony which recommended cost 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 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.  A hearing is scheduled for December 2012.
 
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Flint Creek Plant Environmental Controls

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 September 30, 2012, SWEPCo has incurred $10 million related to this project, including AFUDC.  The APSC staff and the Sierra Club filed testimony that recommended the APSC deny the requested declaratory order.  A hearing at the APSC was held in October 2012 and a decision is pending from the APSC.  If SWEPCo is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC which requested approval for (a) full cost recovery through base rates by 2026 of an estimated $256 million of new environmental investment that will be incurred prior to 2016 at Northeastern Station Unit 3, (b) full cost recovery through 2026 of Northeastern Station Units 3 and 4 net book value (combined net book value of the two units is $235 million as of September 30, 2012), (c) full cost recovery through base rates of an estimated $83 million of new investment incurred through 2016 at various gas units and (d) a new 15-year purchase power agreement with Calpine Oneta Power, effective in 2016, with cost recovery through a rider, including an earnings component of $3 million.  Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery when filing its next base rate case, which is expected to occur no later than 2014.

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 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.  The Arkansas SIP was disapproved and the state is developing a revised submittal.  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.  This rule is being challenged in the United States Court of Appeals for the District of Columbia Circuit and its fate is uncertain given recent developments in the CSAPR litigation.

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.
 
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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.  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 were reduced significantly in the final rule.  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.  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.

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.  In August 2012, the panel issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the Clean Air Interstate Rule until a replacement rule is finalized.  The majority determined that the CAA does not allow the Federal EPA to “overcontrol” emissions in an upwind state and that the Federal EPA exceeded its statutory authority by failing to allow states an opportunity to develop their own implementation plans before issuing a FIP.  The Federal EPA and other respondents have filed petitions for rehearing.  Separate appeals of the supplemental rule, the Error Corrections Rule and the further revisions have been filed, but are being held in abeyance until the court responds to the rehearing petition in the main CSAPR 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.
 
 
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.  The Federal EPA granted petitions to reconsider certain issues related to the new source standards.  Action by the court on these severed issues is being held in abeyance pending action on those petitions.  The case is proceeding on the remaining issues and briefing is scheduled to be completed by April 2013.
 
211

 
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 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 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 sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs.  A petition for rehearing was filed and the court ordered the Federal EPA to respond in October 2012.   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.
 
212

 
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.
 
213

 
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 third 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 September 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 third 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 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 from the Turk Plant.  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.

Approval of ESP order in Ohio may be overturned on rehearing. – Affecting AEP and OPCo

In August 2012, the PUCO issued an order which adopted and modified a new ESP through May 2015.  In September 2012, OPCo and intervenors filed applications with the PUCO for rehearing.  Rehearing of this order is pending at the PUCO.  If the PUCO reverses all or part of the ESP order, it could reduce future net income and cash flows and impact financial condition.

We may not fully collect deferred capacity costs. – Affecting AEP and OPCo

The PUCO adopted and modified the new ESP and established a non-bypassable Retail Stability Rider (RSR).  A portion of the RSR provides for the collection of deferred capacity costs.  The deferred capacity costs may exceed the amount we will collect under the RSR.  In addition, the Industrial Energy Users-Ohio filed a claim before the Supreme Court of Ohio stating, among other things, that OPCo’s recovery of its capacity costs is illegal.  If OPCo is ultimately not permitted to fully collect its deferred capacity costs, it would reduce future net income and cash flows and impact financial condition.

We may not recover deferred fuel costs. – Affecting AEP and OPCo

In August 2012, the PUCO ordered recovery of deferred fuel costs beginning September 2012 through the Phase-In Recovery Rider.  The August 2012 order was upheld by the PUCO in October 2012.  OPCo and intervenors may file appeals at the Supreme Court of Ohio.  No filings at the Supreme Court of Ohio have been made at this time.  If appeals are filed and the Supreme Court of Ohio does not permit full recovery of OPCo’s deferred fuel costs, it would reduce future net income and cash flows and impact financial condition.
 
215

 
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.  In addition, intervenors are challenging various issues at the Supreme Court of Ohio, 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.  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.  In addition, an intervenor filed a claim for refund with the Supreme Court of Ohio.  If the PUCO and/or the Supreme Court of Ohio ultimately determines that additional amounts should benefit ratepayers, 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 October 2012, the PUCO approved OPCo’s corporate separation plan for its generation assets.  Additional filings at the FERC and other state commissions related to corporate separation are expected to be filed in the fourth quarter of 2012.  If all regulatory approvals are received, our results of operations related to generation in Ohio will be largely 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 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 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 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 with the FERC to terminate the Interconnection Agreement in the fourth quarter of 2012.  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) imposing pervasive regulation by the Commodity Futures Trading Commission (CFTC) on dealers and traders who hold significant positions in swaps, (b) requiring standardized OTC derivatives to be traded on registered exchanges as directed by CFTC, (c) imposing new and potentially higher capital and margin requirements on swap dealers and traders who hold significant positions in swaps and (d) increasing the monitoring and compliance obligations of parties who engage in swaps with governmental entities.  The CFTC has issued regulations exempting end users of energy commodities from being required to clear OTC derivatives if they are hedging commercial risk and satisfying certain other requirements, which could reduce the effect of the law's clearing requirements on our hedging activity.  The CFTC has also issued rules that further define the OTC derivative products and entities subject to additional regulatory oversight, which recently became effective.  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.

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 September 30, 2012.
 
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Item 5.  Other Information

NONE

Item 6.  Exhibits

10 – AEP Long-Term Incentive Plan Amended and Restated as of September 25, 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:  October 26, 2012
 
 
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