q313aep10q.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended September 30, 2013
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 as of
October 24, 2013
       
American Electric Power Company, Inc.
    
487,290,382
     
($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, 2013
                     
                   
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
        
33
 
Index of Condensed Notes to Condensed Consolidated Financial Statements
    
39
                     
Appalachian Power Company and Subsidiaries:
              
 
Management’s Narrative Discussion and Analysis of Results of Operations
    
89
 
Condensed Consolidated Financial Statements
        
96
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
  
102
                     
Indiana Michigan Power Company and Subsidiaries:
              
 
Management’s Narrative Discussion and Analysis of Results of Operations
    
104
 
Condensed Consolidated Financial Statements
        
111
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
  
117
                     
Ohio Power Company and Subsidiaries:
              
 
Management’s Narrative Discussion and Analysis of Results of Operations
    
119
 
Condensed Consolidated Financial Statements
        
128
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
  
134
                     
Public Service Company of Oklahoma:
              
 
Management’s Narrative Discussion and Analysis of Results of Operations
    
136
 
Condensed Financial Statements
            
140
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
  
146
                     
Southwestern Electric Power Company Consolidated:
            
 
Management’s Narrative Discussion and Analysis of Results of Operations
    
148
 
Condensed Consolidated Financial Statements
        
154
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
  
160
                     
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
      
161
                     
Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries
      
230
                     
Controls and Procedures
                
237
 
 
 
 
                     
Part II.  OTHER INFORMATION
              
                     
 
Item 1.
   Legal Proceedings        
238
 
Item 1A.
   Risk Factors        
238
 
Item 2.
   Unregistered Sales of Equity Securities and Use of Proceeds  
240
 
Item 4.
   Mine Safety Disclosures      
240
 
Item 5.
   Other Information        
240
 
Item 6.
   Exhibits:          
240
      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
                
241
                     
                     
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., an electric 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.
AEPGenCo
  
AEP Generation Resources Inc., a nonregulated AEP subsidiary in the Generation and Marketing segment.
AEP System
  
American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP Transmission Holding Company
  
AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEPSC
  
American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo
  
American Electric Power Transmission Company, a wholly-owned subsidiary of AEP Transmission Holding Company.
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.
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.
CWIP
  
Construction Work in Progress.
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.
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.
 
 
i
 
FASB
  
Financial Accounting Standards Board.
Federal EPA
  
United States Environmental Protection Agency.
FERC
  
Federal Energy Regulatory Commission.
FGD
  
Flue Gas Desulfurization or scrubbers.
FTR
  
Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP
  
Accounting Principles Generally Accepted in the United States of America.
I&M
  
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IEU
  
Industrial Energy Users-Ohio.
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.
NOx
  
Nitrogen oxide.
Nonutility Money Pool
  
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NSR
  
New Source Review.
OCC
  
Corporation Commission of the State of Oklahoma.
Ohio Phase-in-Recovery Funding
  
Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.
OPCo
  
Ohio Power Company, an AEP electric utility subsidiary.
OPEB
  
Other Postretirement Benefit Plans.
OTC
  
Over the counter.
OVEC
  
Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PJM
  
Pennsylvania – New Jersey – Maryland regional transmission organization.
PM
  
Particulate Matter.
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.
 
 
ii
 
Rockport Plant
  
A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana.  AEGCo and I&M jointly-own Unit 1.  In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
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.
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.
SSO
  
Standard service offer.
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 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 Discussion and Analysis of Financial Condition and Results of Operations” of the 2012 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, growth or contraction within and changes in market demand and demographic patterns in our service territory.
·
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 drought conditions, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
·
Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·
Availability of necessary generating capacity and the performance of our generating plants.
·
Our ability to recover 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 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 capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.
 
 
iv
 
·
Changes in utility regulation and the allocation of costs within regional transmission organizations, including PJM and SPP.
·
The transition to market and the legal separation of generation in Ohio, including the implementation of ESPs and the successful approval, where applicable, and transfer of such Ohio generation assets and liabilities to regulated and nonregulated entities at book value.
·
Our ability to successfully manage negotiations with stakeholders and obtain regulatory approval to terminate 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 Part I of the 2012 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

Corporate Separation, Plant Transfers and Termination of Interconnection Agreement

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets at net book value (NBV) to AEPGenCo.  AEPGenCo will also assume the associated generation liabilities.  In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.  A decision from the Supreme Court of Ohio is pending.  In October 2013, OPCo filed an application with the PUCO to amend the corporate separation plan by permitting OPCo to retain certain rights to purchase power from OVEC.

Also in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations.  The filings requested approval to transfer at NBV approximately 9,200 MW of OPCo-owned generation assets to AEPGenCo.  The AEP East Companies also requested FERC approval to transfer at NBV OPCo’s current two-thirds ownership in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests.  In December 2012, APCo and KPCo filed requests with their respective commissions for the approval of these plant transfers.

In April 2013, the FERC issued orders approving the merger of APCo and WPCo and approving the transfer of OPCo’s generation assets to AEPGenCo and the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo, to be effective using our requested date of December 31, 2013.  In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo.  OPCo has contested the petition for rehearing, which remains pending before the FERC.  In July 2013, the Virginia SCC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax.  Additionally, the Virginia SCC denied the proposed transfer of OPCo’s one-half interest in the Mitchell Plant to APCo.  APCo plans to pursue cost recovery of the transferred interest in the Amos Plant in Virginia in the 2014 biennial filing.  Management is currently evaluating the implications of this order while awaiting a final decision from the WVPSC.  Hearings in the plant transfer case were held at the WVPSC in July 2013.  In September 2013, a WVPSC staff brief advocated for the approval of the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo, also at a reduced amount for rate purposes, and the denial of the proposed transfer of OPCo’s one-half interest in the Mitchell Plant to APCo.  Any disallowance related to recovery of Amos Plant, Unit 3, as a result of Virginia SCC or WVPSC orders, would be recorded upon the transfer, expected in the fourth quarter of 2013.  In October 2013, the KPSC issued an order approving a modified settlement agreement that included a limitation that the net book value of the Mitchell Plant transfer not exceed the amount to be determined by the pending WVPSC order.  Additionally, the order rejected our request to defer FGD project costs for Big Sandy Plant, Unit 2.  As a result of this order, in the third quarter of 2013, KPCo recorded a pretax impairment of $33 million in Asset Impairments and Other Related Charges on the statement of income.  See the “Plant Transfers” sections of APCo and WPCo Rate Matters and KPCo Rate Matters in Note 3 and the “2013 Kentucky Base Rate Case” section below.

The AEP East Companies also requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ power supply resources.  Under the PCA, APCo, I&M and KPCo would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies.  In March 2013, a revised PCA was filed at the FERC that included certain clarifying wording changes agreed upon by intervenors.  A decision is pending at the FERC.  See the “Corporate Separation and Termination of Interconnection Agreement” section of Note 3.

Additionally, FERC approval was sought for a power supply agreement between AEPGenCo and OPCo.  This agreement provides for AEPGenCo to supply capacity for OPCo’s switched and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that is not acquired through an auction from January 1, 2014 through December 31, 2014.

 
1
 
In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by recent orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation.  See the “Plant Transfers” section of APCo and WPCo Rate Matters and the “Plant Transfer” section of KPCo Rate Matters for a discussion of those orders.  

If corporate separation is approved as filed, for any AEPGenCo generation not serving OPCo’s retail load, AEPGenCo’s results of operations will be largely determined by prevailing market conditions effective January 1, 2014.  If incurred costs are not ultimately recovered, it could reduce future net income and cash flows and impact financial condition.

Ohio Electric Security Plan Filing

2009 – 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover OPCo’s deferred fuel costs in rates beginning September 2012.  As of September 30, 2013, OPCo’s net deferred fuel balance was $467 million, excluding unrecognized equity carrying costs.  Decisions from the Supreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance.
 
June 2012 – May 2015 Ohio ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015, which was generally upheld in PUCO rehearing orders in January and March 2013.

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 up to $188.88/MW day.  The RPM price is approximately $33/MW day through May 2014.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.  As of September 30, 2013, OPCo’s incurred deferred capacity costs balance was $228 million, including debt carrying costs.

As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR 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 recovery of deferred capacity costs.  In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR.

In June 2013, intervenors in the competitive bid process (CBP) docket filed recommendations that include prospective rate reductions for capacity and non-energy FAC issues.  OPCo maintains that the August 2012 ESP order fixed OPCo’s non-energy generation rates through December 31, 2014 and ordered the application of a $188.88/MW day price for capacity for non-shopping customers effective January 1, 2015.  However, intervenors maintained that OPCo’s non-energy generation rates should be reduced prior to January 1, 2015 to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned (10% prior to June 2014 and 60% for the period June 1, 2014 through December 31, 2014).  Depending upon actual customer switching levels and the timing of the auctions, OPCo estimates that these capacity issues could reduce OPCo’s projected future revenues by up to approximately $155 million for the period January 2014 through May 2015, if adopted by the PUCO. An additional proposal to prospectively offset deferred capacity costs based upon the results of the energy-only auctions was not quantified and OPCo maintains that proposal should not be adopted in light of prior PUCO orders.  Hearings related to the CBP were held at the PUCO in June and July 2013.  A decision from the PUCO is pending. 

If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its deferred capacity costs, it could reduce future net income and cash flows and impact financial condition.  See “Ohio Electric Security Plan Filing” section of Note 3.

 
2
 
Ohio Customer Choice

In our Ohio service territory, various CRES providers are targeting retail customers by offering alternative generation service.  The reduction in gross margin as a result of customer switching in Ohio 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 and (e) revenues from AEP Energy.  AEP Energy is our CRES provider and part of our Generation and Marketing segment which targets retail customers, both within and outside of our retail service territory.

Customer Demand

In comparison to 2012, our weather-normalized retail sales were down 1.5% and 1.9% for the three and nine months ended September 30, 2013, respectively.  Our industrial sales declined 3.9% and 5.1%, respectively, partially due to lower production levels at Ormet, a large aluminum company.  Ormet has a contract to purchase power from OPCo through 2018.  In October 2013, Ormet announced that it is unable to emerge from bankruptcy and that it has shut down its operations effective immediately.  The loss of Ormet's load will not have a material impact on future gross margin.  Power previously sold to Ormet will be available to be sold into wholesale markets.

PJM Capacity Market

If corporate separation and asset transfers are approved as filed, AEPGenCo will be subject to the PJM capacity auction prices after May 2015 for the majority of the current OPCo-owned generation assets.  Under the previously approved June 2012 – May 2015 ESP, OPCo is allowed to receive revenues through May 2015 for the generation assets from base generation rates and allowed to defer incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The PJM base capacity price for the planning year June 2015 through May 2016 was previously announced as $136.00/MW day.  In May 2013, PJM announced the base capacity auction price for the June 2016 through May 2017 planning period would be $59.37/MW day.

Significantly Excessive Earnings Test

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  In October 2013, the PUCO issued an order on the 2010 SEET filing.  As a result, the PUCO ordered a $7 million refund of pretax earnings to customers.  OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis.  Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in 2012 for OPCo.  Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo.  Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition.  See the “Ohio Electric Security Plan Filing” section of Note 3.

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.  As of September 30, 2013, SWEPCo’s share of incurred construction expenditures for the Turk Plant was approximately $1.8 billion, including AFUDC and capitalized interest of $328 million and related transmission costs of $118 million.  As of September 30, 2013, a provision of $173 million has been recorded for costs incurred in excess of a Texas cost cap, resulting in total capitalized expenditures of $1.6 billion.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant.  In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN.  The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market.  If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.  See the “Turk Plant” section of Note 3.

 
3
 
2012 Texas Base Rate Case

In 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 operation and maintenance costs.  In September 2012, an Administrative Law Judge (ALJ) 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.  In May 2013, the ALJ issued a proposal for decision recommending a rate increase but found SWEPCo imprudent for failing to cancel the Turk Plant in 2010.

The PUCT rejected the ALJ’s imprudence recommendation, but during a September 2013 open meeting, the PUCT stated that it would limit the recovery of the investment in the Turk Plant by imposing a Texas jurisdictional cost cap established in the recently concluded Certificate of Convenience and Necessity (CCN) case appeal (the Texas capital cost cap).  The PUCT also provided new details on how the cost cap would be applied.  In October 2013, the PUCT issued an order with the determination that the Turk Plant Texas capital cost cap also limited SWEPCo’s recovery of AFUDC in addition to its recovery of cash construction costs.  As a result of the determination that AFUDC was to be included in the cap, in the third quarter of 2013, SWEPCo recorded an additional pretax impairment of $111 million in Asset Impairments and Other Related Charges on the statement of income.  The order approved an annual rate increase of approximately $39 million based upon a return on common equity of 9.65%.  As a result of this approval, SWEPCo retroactively applied these rates back to the end of January 2013.  The approval also provided for the following:  (a) no disallowances to the existing book investment in the Stall Plant, and (b) the exclusion, until SWEPCo files and obtains approval of a Transmission Cost Recovery Rider, of the Turk Plant transmission line investment that was not in service at the end of the test year.  Additionally, the PUCT determined that it would defer consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.  Requests for rehearing may be filed within 30 days of receipt of the PUCT order.  SWEPCo intends to file a motion for rehearing with the PUCT in late October 2013.

If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Turk Plant, transmission lines or Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.  See the “2012 Texas Base Rate Case” section of Note 3.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant.  In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013.  The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund.  The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013.  In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant.  If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.  See the “2012 Louisiana Formula Rate Filing” section of Note 3.

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%.  In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates to $92 million.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the order with the Indiana Court of Appeals.  In September 2013, the OUCC filed a brief on appeal that included objections to certain aspects of the rate case.  If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.  See the “2011 Indiana Base Rate Case” section of Note 3.

 
4
 
2013 Kentucky Base Rate Case

In June 2013, KPCo filed a request with the KPSC for an annual increase in base rates of $114 million based upon a return on common equity of 10.65% to be effective January 2014.  The proposed revenue increase includes cost recovery of the pending transfer of the one-half interest in the Mitchell Plant (780 MW).  In October 2013, the KPSC issued an order which modified and approved a settlement agreement relating to the proposed transfer of the one-half interest in the Mitchell Plant, in which KPCo agreed to withdraw this base rate case request.  KPCo intends to withdraw this base rate request following the resolution of any potential requests for rehearing or appeals of the KPSC order.  Assuming KPCo withdraws the base rate case, current base rates will remain in effect until at least May 2015.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of September 30, 2013, I&M has incurred $285 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items which the IURC stated I&M could seek recovery in a base rate case.  I&M was granted recovery through an LCM rider which will be determined by a proceeding in the fourth quarter of 2013 and semi-annual proceedings thereafter.  The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in its rates.  In October 2013, I&M filed an application with the IURC for LCM rider rates to be effective January 2014.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to certain projects effective January 2013 until these costs are included in rates.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON.

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.  See “Cook Plant Life Cycle Management Project (LCM Project)” section of Note 3.

Repositioning Efforts

In April 2012, we initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings.  This process has included evaluations of our employee and retiree benefit programs as well as evaluations of the functional effectiveness and staffing levels of our finance and accounting, information technology, generation and supply chain and procurement organizations.  While we have completed certain aspects of this program, our ongoing review of repositioning opportunities continues to yield cost savings for many of our subsidiaries, allowing us to direct many of these savings into growth areas of our business.

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 Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report.  Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies included herein.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

 
5
 
Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in Federal Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.  In October 2013, we filed a motion to dismiss the case.  We will continue to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with 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 (HAPs) from fossil fuel-fired power plants, 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, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court.  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 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 Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report.  We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.   Recovery in Ohio will be dependent upon prevailing market conditions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If we are unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of September 30, 2013, the AEP System had a total generating capacity of 37,600 MWs, of which 23,700 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 and our current plan for corporate separation effective January 1, 2014, investments to meet these proposed requirements range from approximately $3.5 billion to $4 billion from 2013 through 2020 including amounts related to nonregulated plants.  These amounts include investments to convert some of our coal generation units to natural gas.  If natural gas conversion is not completed, the units could be retired 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.  In addition, we are continuing to evaluate the economic feasibility of environmental investments on nonregulated plants.

 
6
 
Subject to the factors listed above and based upon our continuing evaluation, we intend 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 1-4
 
 
 995 
KPCo
 
Big Sandy Plant, Unit 2
 
 
 800 
OPCo
 
Kammer Plant
 
 
 630 
OPCo
 
Muskingum River Plant, Units 1-5
 
 
 1,440 
OPCo
 
Picway Plant
 
 
 100 
PSO
 
Northeastern Station, Unit 4
 
 
 470 
SWEPCo
 
Welsh Plant, Unit 2
 
 
 528 
Total
 
 
 
 
 6,533 

As of September 30, 2013, the net book value of all of OPCo’s units above was zero and the net book value, before cost of removal, including related material and supplies inventory and CWIP balances of the other plants in the table above was $1 billion.

In the second quarter of 2013, we re-evaluated potential courses of action with respect to the planned operation of Muskingum River Plant, Unit 5 and concluded that completion of a refueling project which would extend the unit’s useful life is remote.  As a result, in the second quarter of 2013, we completed an impairment analysis and recorded a $154 million pretax ($99 million, net of tax) impairment charge for OPCo’s net book value of Muskingum River Plant, Unit 5.  We expect to retire the plant no later than 2015.  See “Muskingum River Plant, Unit 5” section of Note 5.
 
In addition, we are in the process of obtaining permits and other necessary regulatory approvals for either the conversion of some of our coal units to natural gas or installing emission control equipment on certain units.  The following table lists the plants or units that are either awaiting regulatory approval or are still being evaluated by management based on changes in emission requirements and demand for power:

 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs) 
APCo
 
Clinch River Plant, Units 1-2
 
 
 470 
I&M/AEGCo/KPCo
 
Rockport Plant, Units 1-2
 
 
 2,620 
KPCo
 
Big Sandy Plant, Unit 1
 
 
 278 
PSO
 
Northeastern Station, Unit 3
 
 
 460 
SWEPCo
 
Welsh Plant, Units 1 & 3
 
 
 1,056 
Total
 
 
 
 
 4,884 

As of September 30, 2013, the net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the plants in the table above was $1.4 billion.

Volatility in natural gas prices, pending environmental rules and other market factors could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of coal-fired units.  For regulated plants that we may close early, we are seeking regulatory recovery of remaining net book values.  To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows.

 
7
 
Modification of the NSR Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between the AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when it undertook various equipment repair and replacement projects over a period of nearly 20 years.  The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOx emissions from the AEP System and various mitigation projects.

The original consent decree required certain types of control equipment to be installed at Muskingum River Plant, Unit 5, Big Sandy Plant, Unit 2 and the two units of the Rockport Plant in 2015, 2017 and 2019, respectively.  In January 2013, an agreement to modify the consent decree was reached and filed with the court.  The terms of the agreement include more options for the affected units (including alternative control technologies, re-fueling and/or retirement), more stringent SO2 emission caps for the AEP System and additional mitigation measures.  The Federal EPA sought public comments on the modification prior to its entry by the court in May 2013.  For the units of the Rockport Plant, the modified decree requires installation of dry sorbent injection technology for SO2 control on both units in 2015 and imposes a declining plant-wide cap on SO2 emissions beginning in 2016.

Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a Dry Sorbent Injection system.  The estimated cost in the application was $285 million, excluding AFUDC to be shared equally between I&M and AEGCo.  In July 2013, a settlement agreement was filed with the IURC.  The settlement agreement includes the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s ownership share.  A hearing was held at the IURC in August 2013 and a decision is expected by November 2013.  As of September 30, 2013, we have incurred costs of $93 million related to the CCT Project, including AFUDC.  If we are not ultimately permitted to recover our incurred costs, it could reduce future net income and cash flows.  See the “Rockport Plant Clean Coal Technology Project (CCT Project)” section of Note 3.

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES), Unit 4 in 2016 and additional environmental controls on NES, Unit 3 to continue operations through 2026.  As of September 30, 2013, the net book values of NES, Units 3 and 4 were $182 million and $101 million, respectively, before cost of removal, including materials and supplies inventory and CWIP.  In August 2013, the OCC dismissed PSO’s environmental compliance plan case without prejudice but will permit PSO to seek recovery in a future proceeding.  PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan.  If PSO is ultimately not permitted to fully recover its net book value of NES, Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC.  Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC.  As of September 30, 2013, SWEPCo has incurred $17 million in costs related to these projects.  Management intends to seek recovery of these projects from SWEPCo’s state commissions.

 
8
 
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 U.S. Court of Appeals for the District of Columbia Circuit and its fate is uncertain given developments in the CSAPR litigation.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for PM, SO2, NOx and lead, and is currently reviewing the NAAQS for ozone.  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 was 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 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 U.S. 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 filed petitions for rehearing but in January 2013, the U.S. Court of Appeals for the District of Columbia Circuit denied all petitions for rehearing.  The petition for further review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013.  Separate appeals of the supplemental rule, the Error Corrections Rule and the further revisions have been filed, but are being held in abeyance.

 
9
 
The time frames and stringency of the required emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and our electric utility customers.  We cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In February 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  The effective date of the final rule was April 16, 2012 and compliance is required within three years.  We are participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed.  In 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards.   Revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions, were issued by the Federal EPA in March 2013.  The Federal EPA has reopened the public comment period to consider additional changes to the start-up and shut down provisions.

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 U.S. Court of Appeals for the District of Columbia Circuit by several organizations of which we are members.  Certain issues related to the standards for new coal-fired units have been severed from the main case and are being held in abeyance pending completion of the Federal EPA’s reconsideration proceeding.  The case is proceeding on the remaining issues and briefing was completed in April 2013.

Regional Haze

In 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.  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 November 2012, we notified the court that the parties had reached agreement on a settlement 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 Tenth Circuit Court of Appeals is holding the appeal in abeyance pending implementation of the settlement.  A revised regional haze SIP has been adopted by the State of Oklahoma.  The Federal EPA proposed approval of the revised SIP.

 
10
 
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.  New source performance standards affect units that have not yet received permits.  The proposed standards were challenged in the U.S. Court of Appeals for the District of Columbia Circuit.  That case was dismissed because the court determined that no final agency action had yet been taken.

In June 2013, President Obama issued a memorandum to the Administrator of the Federal EPA directing the agency to develop and issue a new proposal regulating carbon emissions from new electric generating units in September 2013.  The new proposal was issued in September 2013 and requires new large natural gas units to meet 1,000 pounds of CO2 per MWh of electricity generated and small natural gas units to meet 1,100 pounds of CO2 per MWh.  New coal-fired units are required to meet the 1,100 pounds of CO2 per MWh with the option to meet the tighter limits if they choose to average emissions over multiple years.  The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from existing, modified and reconstructed electric generating units before June 2014, to finalize those standards by June 2015 and to require states to submit revisions to their implementation plans including such standards no later than June 2016.  The President directed the Federal EPA, in developing this proposal, to directly engage states, leaders in the power sector, labor leaders and other stakeholders, to tailor the regulations to reduce costs, to develop market-based instruments and allow regulatory flexibilities and “assure that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power.”  We cannot currently predict the impact these programs may have on future resource plans or our existing generating fleet, but the costs may be substantial.

In June 2012, the U.S. 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 which the court denied in December 2012.  The U.S. Supreme Court granted several petitions for review and will determine whether the Federal EPA made a reasonable determination that adoption of the motor vehicle standards trigger PSD and Title V permitting obligations for stationary sources.  A decision is expected by June 2014.

The Federal EPA also finalized a rule in June 2012 that retains the current CO2 emission 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 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 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
 
 
11
 
uses of coal ash.  Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule.  The Federal EPA opposed the petition and is seeking additional time to coordinate the issuance of a final rule with the issuance of new effluent limitations under the Clean Water Act for utility facilities.  In October 2013, the U.S. District Court for the District of Columbia issued an order stating that it intended to partially rule in favor of the Federal EPA for dismissal of two counts and rule in favor of the environmental organizations on one count.  However, the court also stated that a Memorandum Opinion and Final Order would be forthcoming and until issued we are unable to predict the impact of the court’s ruling.

Currently, approximately 40% of the coal ash and other residual products from our generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses.  Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes.  In addition, we currently use surface impoundments and landfills to manage these materials at our generating facilities and will incur significant costs to upgrade or close and replace these existing facilities under the proposed solid waste management alternative.  Regulation of these materials as hazardous wastes would significantly increase these costs.  As the rule is not final, we are unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

Clean Water Act Regulations

In 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 November 2013.  We are preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

In addition, the Federal EPA issued an information collection request and is developing revised effluent limitation guidelines for electricity generating facilities.  A proposed rule was signed in April 2013 with a final rule expected in 2014.  The Federal EPA proposed eight options of increasing stringency and cost for fly ash and bottom ash transport water, scrubber wastewater, leachate from coal combustion byproduct landfills and impoundments and other wastewaters associated with coal-fired generating units, with four labeled preferred options.  Certain of the Federal EPA's preferred options have already been implemented or are part of our long-term plans.  We will review the proposal in detail to evaluate whether our plants are currently meeting the proposed limitations, what technologies have been incorporated into our long-range plans and what additional costs might be incurred if the Federal EPA's most stringent options were adopted.  We submitted detailed comments to the Federal EPA in September 2013 and participated in comments filed by various organizations of which we are members.

Climate Change

National public policy makers and regulators in the 11 states we serve have diverse views on climate change.  We are currently focused on responding to these emerging views with prudent actions, such as improving energy efficiency, investing in developing cost-effective and less carbon-intensive technologies and evaluating our assets across a range of plausible scenarios and outcomes.  We are also active participants in a variety of public policy discussions at state and federal levels to assure that proposed new requirements are feasible and the economies of the states we serve are not placed at a competitive disadvantage.

 
12
 
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.  The majority of the states where we have generating facilities have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements.  We are taking steps to comply with these requirements.

Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others.  We are no longer a party to any such cases.  See Note 4.

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

For additional information on climate change, other environmental issues and the actions we are taking to address potential impacts, see Part I of the 2012 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 
13
 
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.

Our reportable segments and their related business activities are outlined 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 Net Income by segment for the three and nine months ended September 30, 2013 and 2012.

 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2013 
 
2012 
 
2013 
 
2012 
 
 
(in millions)
Utility Operations
$
 409 
 
$
 471 
 
$
 980 
 
$
 1,220 
Transmission Operations
 
 22 
 
 
 14 
 
 
 53 
 
 
 31 
AEP River Operations
 
 (1)
 
 
 (1)
 
 
 (12)
 
 
 11 
Generation and Marketing
 
 4 
 
 
 10 
 
 
 15 
 
 
 4 
All Other (a)
 
 - 
 
 
 (6)
 
 
 101 
 
 
 (25)
Net Income
$
 434 
 
$
 488 
 
$
 1,137 
 
$
 1,241 

(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.

 
14
 
AEP CONSOLIDATED

Third Quarter of 2013 Compared to Third Quarter of 2012

Net Income decreased from $488 million in 2012 to $434 million in 2013 primarily due to:

·
Impairments during the third quarter of 2013 for the following:
 
·
A decision by the PUCT determining that AFUDC on the Turk Plant was included in the Texas capital cost cap.
 
·
A decision from the KPSC disallowing scrubber costs on KPCo's Big Sandy Plant.
·
A decrease in weather-related usage.
·
The loss of retail customers in Ohio to various CRES providers.

These decreases were partially offset by:

·
Successful rate proceedings in various jurisdictions.
·
The deferral of Ohio capacity costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
·
A decrease in Ohio depreciation expense due to the impairments of certain Ohio generation plants.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Net Income decreased from $1,241 million in 2012 to $1,137 million in 2013 primarily due to:

·
Impairments during 2013 for the following:
 
·
Muskingum River Plant, Unit 5.
 
·
A decision by the PUCT determining that AFUDC on the Turk Plant was included in the Texas capital cost cap.
 
·
A decision from the KPSC disallowing scrubber costs on KPCo's Big Sandy Plant.
·
The loss of retail customers in Ohio to various CRES providers.
·
A decrease in margins from off-system sales primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity revenues and reduced trading and marketing margins.
·
An increase in plant outages during 2013.
·
A decrease in AEP River Operations' 2013 earnings due to unfavorable operating conditions caused by extremely low water levels in the first quarter of 2013 followed by flood conditions later in the spring as well as significant reductions in grain and export coal demand.
·
A decrease 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.
·
 An increase in other variable electric generation expenses during 2013.

These decreases were partially offset by:

·
Successful rate proceedings in various jurisdictions.
·
The deferral of Ohio capacity costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
·
A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.
·
A decrease in Ohio depreciation expense due to the impairments of certain Ohio generation plants.

Our results of operations are discussed below by operating segment.

 
15
 
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.

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2013 
 
2012 
 
2013 
 
2012 
 
 
(in millions)
Revenues
$
 3,819 
 
$
 3,839 
 
$
 10,614 
 
$
 10,482 
Fuel and Purchased Electricity
 
 1,368 
 
 
 1,401 
 
 
 3,775 
 
 
 3,766 
Gross Margin
 
 2,451 
 
 
 2,438 
 
 
 6,839 
 
 
 6,716 
Other Operation and Maintenance
 
 802 
 
 
 858 
 
 
 2,487 
 
 
 2,383 
Asset Impairments and Other Related Charges
 
 144 
 
 
 13 
 
 
 298 
 
 
 13 
Depreciation and Amortization
 
 433 
 
 
 458 
 
 
 1,268 
 
 
 1,318 
Taxes Other Than Income Taxes
 
 222 
 
 
 219 
 
 
 644 
 
 
 632 
Operating Income
 
 850 
 
 
 890 
 
 
 2,142 
 
 
 2,370 
Interest and Investment Income
 
 1 
 
 
 2 
 
 
 10 
 
 
 5 
Carrying Costs Income
 
 8 
 
 
 11 
 
 
 20 
 
 
 42 
Allowance for Equity Funds Used During Construction
 
 11 
 
 
 19 
 
 
 31 
 
 
 59 
Interest Expense
 
 (217)
 
 
 (221)
 
 
 (664)
 
 
 (662)
Income Before Income Tax Expense and Equity
 
 
 
 
 
 
 
 
 
 
 
 
Earnings
 
 653 
 
 
 701 
 
 
 1,539 
 
 
 1,814 
Income Tax Expense
 
 246 
 
 
 231 
 
 
 561 
 
 
 596 
Equity Earnings of Unconsolidated Subsidiaries
 
 2 
 
 
 1 
 
 
 2 
 
 
 2 
Net Income
$
 409 
 
$
 471 
 
$
 980 
 
$
 1,220 

Summary of KWh Energy Sales for Utility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 16,414 
 
 
 17,664 
 
 
 45,299 
 
 
 45,617 
 
Commercial
 
 13,861 
 
 
 14,091 
 
 
 37,964 
 
 
 38,444 
 
Industrial
 
 14,158 
 
 
 14,729 
 
 
 42,521 
 
 
 44,798 
 
Miscellaneous
 
 797 
 
 
 824 
 
 
 2,252 
 
 
 2,325 
Total Retail (a)
 
 45,230 
 
 
 47,308 
 
 
 128,036 
 
 
 131,184 
 
 
 
 
 
 
 
 
 
 
 
 
Wholesale
 
 13,960 
 
 
 12,876 
 
 
 34,164 
 
 
 30,409 
 
 
 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 59,190 
 
 
 60,184 
 
 
 162,200 
 
 
 161,593 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)  Represents energy delivered to distribution customers.

 
16
 
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,
 
 
2013 
 
2012 
 
2013 
 
2012 
 
 
(in degree days)
Eastern Region
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 1 
 
 
 9 
 
 
 1,986 
 
 
 1,388 
Normal - Heating (b)
 
 7 
 
 
 7 
 
 
 1,887 
 
 
 1,923 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 655 
 
 
 816 
 
 
 1,007 
 
 
 1,245 
Normal - Cooling (b)
 
 705 
 
 
 709 
 
 
 1,015 
 
 
 1,012 
 
 
 
 
 
 
 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 - 
 
 
 - 
 
 
 606 
 
 
 348 
Normal - Heating (b)
 
 1 
 
 
 1 
 
 
 588 
 
 
 602 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (d)
 
 1,387 
 
 
 1,525 
 
 
 2,254 
 
 
 2,619 
Normal - Cooling (b)
 
 1,369 
 
 
 1,367 
 
 
 2,217 
 
 
 2,201 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

 
17
 

Third Quarter of 2013 Compared to Third Quarter of 2012
 
 
 
 
 
 
 
 
Reconciliation of Third Quarter of 2012 to Third Quarter of 2013
Net Income from Utility Operations
(in millions)
 
 
 
 
 
 
 
 
Third Quarter of 2012
 
 
 
 
$
 471 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
Retail Margins
 
 
 
 
 
 20 
Off-system Sales
 
 
 
 
 
 (22)
Transmission Revenues
 
 
 
 
 
 29 
Other Revenues
 
 
 
 
 
 (14)
Total Change in Gross Margin
 
 
 
 
 
 13 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 56 
Asset Impairments and Other Related Charges
 
 
 
 
 
 (131)
Depreciation and Amortization
 
 
 
 
 
 25 
Taxes Other Than Income Taxes
 
 
 
 
 
 (3)
Interest and Investment Income
 
 
 
 
 
 (1)
Carrying Costs Income
 
 
 
 
 
 (3)
Allowance for Equity Funds Used During Construction
 
 
 
 
 
 (8)
Interest Expense
 
 
 
 
 
 4 
Equity Earnings of Unconsolidated Subsidiaries
 
 
 
 
 
 1 
Total Change in Expenses and Other
 
 
 
 
 
 (60)
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 (15)
 
 
 
 
 
 
 
 
Third Quarter of 2013
 
 
 
 
$
 409 

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 $20 million primarily due to the following:
 
·
Successful rate proceedings in our service territories which include:
   
·
A $63 million rate increase for SWEPCo.
   
·
A $62 million rate increase for OPCo.
   
·
A $29 million rate increase for I&M.
       
For the rate increases described above, $42 million of these increases relate to riders/trackers which have corresponding increases in expense items below.
   
·
A $16 million increase due to the deferral of consumables and purchased power as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
 
These increases were partially offset by:
 
·
A $70 million decrease attributable to Ohio customers switching to alternative CRES providers.  This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
 
·
A $60 million decrease in weather-related usage primarily due to 20% and 9% decreases in cooling degree days in our eastern and western regions, respectively.
·
Margins from Off-system Sales decreased $22 million primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower physical sales margins, reduced trading and marketing margins and true-up of prior period PJM expenses.  The decrease in CRES capacity revenues is partially offset in expense items below.
·
Transmission Revenues increased $29 million primarily due to increased transmission revenues from Ohio customers who have switched to alternative CRES providers and rate increases for customers in the SPP and PJM region.  The increase in transmission revenues related to CRES providers offsets a portion of the lost revenues included in Retail Margins above.
·
Other Revenues decreased $14 million primarily due to the following:
 
 
18
 
 
·
An $8 million decrease in revenues related to TCC's issuance of securitization bonds in March 2012, which is partially offset by a decrease in Depreciation and Amortization expense.
 
·
A $7 million decrease in revenues due to resolution of contingencies related to pole attachments in the third quarter of 2013.  This decrease in Other Revenues is offset by a decrease in Other Operation and Maintenance expense detailed below.
 
These decreases were partially offset by:
 
·
A $9 million increase in revenues primarily associated with transformer projects for third parties.

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

·
Other Operation and Maintenance expenses decreased $56 million primarily due to the following:
 
·
A $49 million decrease in administrative and general expenses.
 
·
A $19 million decrease in energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
 
·
A $15 million decrease in storm-related expenses.
 
·
A $13 million decrease due to resolution of contingencies related to pole attachments in the third quarter of 2013.  This decrease in Other Operation and Maintenance expense is partially offset by a decrease in Other Revenues detailed above.
 
These decreases were partially offset by:
 
·
A $21 million increase in transmission services due to increased RTO expense within PJM and SPP.  This increase was offset by a corresponding increase in Retail Margins.
 
·
A $19 million increase in remitted Universal Service Fund (USF) surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase was offset by a corresponding increase in Retail Margins.
·
Asset Impairments and Other Related Charges increased by $131 million primarily due to the following:
 
·
A $111 million increase due to the third quarter 2013 write-off of AFUDC on the Turk Plant that was included in the Texas capital cost cap.  This write-off was in accordance with the PUCT's September 2013 open meeting and October 2013 order.
 
·
A $33 million increase due to KPCo's third quarter 2013 write-off of scrubber costs on the Big Sandy Plant and other generation costs in accordance with the KPSC's October 2013 order.
·
Depreciation and Amortization expenses decreased $25 million primarily due to the following:
 
·
A $34 million decrease as a result of depreciation ceasing on certain Ohio generating plants that were impaired in November 2012 and June 2013.
 
·
A $9 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of the capacity deferral mechanism.
 
These decreases were partially offset by:
 
·
An $8 million increase due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant's estimated life approved by the IURC effective March 2013.  The majority of the increase in depreciation for Tanners Creek Plant's life is offset within Gross Margin.
 
·
A $7 million increase due to the Turk Plant being placed in service in December 2012.
 
·
Overall higher depreciable property balances.
·
Allowance for Equity Funds Used During Construction decreased $8 million primarily due to completed construction of the Turk Plant in December 2012.
·
Income Tax Expense increased $15 million primarily due to other book/tax differences which are accounted for on a flow-through basis, partially offset by a decrease in pretax book income.

 
19
 

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012
 
 
 
 
 
 
 
 
Reconciliation of Nine Months Ended September 30, 2012 to Nine Months Ended September 30, 2013
Net Income from Utility Operations
(in millions)
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2012
 
 
 
 
$
 1,220 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
Retail Margins
 
 
 
 
 
 147 
Off-system Sales
 
 
 
 
 
 (98)
Transmission Revenues
 
 
 
 
 
 64 
Other Revenues
 
 
 
 
 
 10 
Total Change in Gross Margin
 
 
 
 
 
 123 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 (104)
Asset Impairments and Other Related Charges
 
 
 
 
 
 (285)
Depreciation and Amortization
 
 
 
 
 
 50 
Taxes Other Than Income Taxes
 
 
 
 
 
 (12)
Interest and Investment Income
 
 
 
 
 
 5 
Carrying Costs Income
 
 
 
 
 
 (22)
Allowance for Equity Funds Used During Construction
 
 
 
 
 
 (28)
Interest Expense
 
 
 
 
 
 (2)
Total Change in Expenses and Other
 
 
 
 
 
 (398)
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 35 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2013
 
 
 
 
$
 980 

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 $147 million primarily due to the following:
 
·
Successful rate proceedings in our service territories which include:
   
·
A $208 million rate increase for OPCo.
   
·
A $109 million rate increase for SWEPCo.
   
·
An $80 million rate increase for I&M.
   
·
A $14 million rate increase for APCo.
       
For the rate increases described above, $142 million of these increases relate to riders/trackers which have corresponding increases in expense items below.
 
·
A $64 million increase due to the deferral of consumables and purchased power as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
 
These increases were partially offset by:
 
·
A $223 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 $35 million decrease 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 $26 million increase in other variable electric generation expenses.
 
·
A $10 million net decrease in weather-related usage primarily due to decreases of 19% and 14% in cooling degree days in our eastern and western regions, respectively, partially offset by increases in heating degree days of 43% and 74% in our eastern and western regions, respectively.
·
Margins from Off-system Sales decreased $98 million primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity revenues, reduced trading and marketing margins and true-up of prior period PJM expenses.  The decrease in CRES capacity revenues is partially offset in expense items below.
·
Transmission Revenues increased $64 million primarily due to increased transmission revenues from Ohio customers who have switched to alternative CRES providers and rate increases for customers in the SPP region.  The increase in transmission revenues related to CRES providers offsets a portion of the lost revenues included in Retail Margins above.
 
 
20
 
·
Other Revenues increased $10 million primarily due to the following:
 
·
A $15 million increase in revenues primarily associated with transformer projects for third parties.
 
This increase was partially offset by:
 
·
A $7 million decrease in revenues due to resolution of contingencies related to pole attachments in the third quarter of 2013.  This decrease in Other Revenues is offset by a decrease in Other Operation and Maintenance expense.

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

·
Other Operation and Maintenance expenses increased $104 million primarily due to the following:
 
·
A $64 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase was offset by a corresponding increase in Retail Margins.
 
·
A $49 million increase in plant outages during 2013.
 
·
A $30 million write-off in the first quarter of 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.
 
·
A $30 million net increase 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.
 
These increases were partially offset by:
 
·
A $28 million decrease due to the deferral of capacity-related costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
 
·
A $25 million decrease due to an agreement reached to settle an insurance claim in the first quarter of 2013.
·
Asset Impairments and Other Related Charges increased $285 million primarily due to the following:
 
·
A $154 million increase due to the second quarter 2013 impairment of Muskingum River Plant, Unit 5.
 
·
A $111 million increase due to the third quarter 2013 write-off of AFUDC on the Turk Plant that was included in the Texas capital cost cap.  This write-off was in accordance with the PUCT's September 2013 open meeting and October 2013 order.
 
·
A $33 million increase due to KPCo's third quarter 2013 write-off of scrubber costs on the Big Sandy Plant and other generation costs in accordance with the KPSC's October 2013 order.
·
Depreciation and Amortization expenses decreased $50 million primarily due to the following:
 
·
A $92 million decrease as a result of depreciation ceasing on certain Ohio generating plants that were impaired in November 2012 and June 2013.
 
·
A $44 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 deferral mechanism.
 
These decreases were partially offset by:
 
·
A $29 million increase due to the Turk Plant being placed in service in December 2012.
 
·
A $23 million increase due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant's estimated life approved by the MPSC effective April 2012 and by the IURC effective March 2013.  The majority of the increase in depreciation for Tanners Creek Plant's life is offset within Gross Margin.
 
·
Overall higher depreciable property balances.
·
Taxes Other Than Income Taxes increased $12 million primarily due to increased property taxes as a result of increased capital investments.
·
Carrying Costs Income decreased $22 million primarily due to the following:
 
·
An $11 million decrease due to an increased recovery of Virginia environmental costs in new base rates as approved by the Virginia SCC in January 2012 and decreased carrying charges related to the Dresden Plant.
 
·
An $8 million decrease in carrying costs income due to the first quarter 2012 recording of debt carrying costs prior to TCC's issuance of securitization bonds in March 2012.
·
Allowance for Equity Funds Used During Construction decreased $28 million primarily due to completed construction of the Turk Plant in December 2012.
·
Income Tax Expense decreased $35 million primarily due to a decrease in pretax book income partially offset by audit settlements for previous years recorded in 2012 and other book/tax differences which are accounted for on a flow-through basis.

 
21
 
TRANSMISSION OPERATIONS

Third Quarter of 2013 Compared to Third Quarter of 2012

Net Income from our Transmission Operations segment increased from $14 million in 2012 to $22 million in 2013 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Net Income from our Transmission Operations segment increased from $31 million in 2012 to $53 million in 2013 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT.

AEP RIVER OPERATIONS

Third Quarter of 2013 Compared to Third Quarter of 2012

Net Income from our AEP River Operations segment was unchanged in comparison to 2012.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Net Income from our AEP River Operations segment decreased from income of $11 million in 2012 to a loss of $12 million in 2013 due to  unfavorable operating conditions caused by extremely low water levels in the first quarter of 2013 followed by flood conditions later in the spring.  In addition, we have experienced significant reductions in grain and export coal demand.

GENERATION AND MARKETING

Third Quarter of 2013 Compared to Third Quarter of 2012

Net Income from our Generation and Marketing segment decreased from $10 million in 2012 to $4 million in 2013 primarily due to decreased retail margins and reduced inception gains from marketing activities, partially offset by favorable gross margins at the Oklaunion Plant.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Net Income from our Generation and Marketing segment increased from $4 million in 2012 to $15 million in 2013 primarily due to higher trading and marketing margins and increased retail activity resulting from our March 2012 acquisition of BlueStar.

ALL OTHER

Third Quarter of 2013 Compared to Third Quarter of 2012

Net Income from All Other increased from a loss of $6 million in 2012 to $0 in 2013 primarily due to a reduction in interest expense due to lower interest rates.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Net Income from All Other increased from a loss of $25 million in 2012 to income of $101 million in 2013 primarily due to a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.

 
22
 
AEP SYSTEM INCOME TAXES

Third Quarter of 2013 Compared to Third Quarter of 2012

Income Tax Expense increased $16 million primarily due to other book/tax differences which are accounted for on a flow through basis and the regulatory accounting treatment of state income taxes, partially offset by a decrease in pretax book income.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Income Tax Expense decreased $100 million primarily due to a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013, a decrease in pretax book income, partially offset by audit settlements for previous years recorded in 2012 and other book/tax differences which are accounted for on a flow through basis.

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, 2013
 
December 31, 2012
 
 
(dollars in millions)
Long-term Debt, including amounts due within one year
$
 17,568 
 
 50.9 
%
 
$
 17,757 
 
 52.3 
%
Short-term Debt
 
 1,218 
 
 3.5 
 
 
 
 981 
 
 2.9 
 
Total Debt
 
 18,786 
 
 54.4 
 
 
 
 18,738 
 
 55.2 
 
AEP Common Equity
 
 15,762 
 
 45.6 
 
 
 
 15,237 
 
 44.8 
 
Noncontrolling Interests
 
 1 
 
 - 
 
 
 
 - 
 
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Debt and Equity Capitalization
$
 34,549 
 
 100.0 
%
 
$
 33,975 
 
 100.0 
%

Our ratio of debt-to-total capital declined from 55.2% as of December 31, 2012 to 54.4% as of September 30, 2013 primarily due to an increase in our common equity from earnings.

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, 2013, we had $4.5 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.

 
23
 
Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  As of September 30, 2013, our available liquidity was approximately $3.3 billion as illustrated in the table below:

 
 
 
Amount
 
 
Maturity
 
 
 
(in millions)
 
 
 
Commercial Paper Backup:
 
 
 
 
 
 
 
Revolving Credit Facility
 
$
 1,750 
 
 
June 2016
 
Revolving Credit Facility
 
 
 1,750 
 
 
July 2017
Term Credit Facility
 
 
 1,000 
 
 
May 2015
Total
 
 
 4,500 
 
 
 
Cash and Cash Equivalents
 
 
 147 
 
 
 
Total Liquidity Sources
 
 
 4,647 
 
 
 
Less:
AEP Commercial Paper Outstanding
 
 
 518 
 
 
 
 
Letters of Credit Issued
 
 
 185 
 
 
 
 
Draw on Term Credit Facility
 
 600 
 
 
 
 
 
 
 
 
 
 
 
Net Available Liquidity
 
$
 3,344 
 
 
 

We have credit facilities totaling $3.5 billion to support our commercial paper program.  The credit facilities allow us to issue letters of credit in an amount up to $1.2 billion.

We use our commercial paper program to meet the short-term borrowing needs of our subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  The maximum amount of commercial paper outstanding during the first nine months of 2013 was $904 million.  The weighted-average interest rate for our commercial paper during 2013 was 0.32%.

In February 2013, we entered into a $1 billion term credit facility due in May 2015 to fund certain OPCo maturities on an interim basis and to facilitate the corporate separation of generation assets from transmission and distribution.  In July 2013, we terminated the $1 billion term credit facility.  In July 2013, AEPGenCo, APCo, KPCo and OPCo entered into a $1 billion term credit facility due in May 2015 to fund certain OPCo maturities on an interim basis and to facilitate the corporate separation of generation assets from transmission and distribution.

Securitized Accounts Receivable

In June 2013, we amended our receivables securitization agreement.  The agreement provides a commitment of $700 million from bank conduits to purchase receivables.  We amended a commitment of $385 million to expire in June 2014.  The remaining commitment of $315 million expires in June 2015.

West Virginia Securitization of Regulatory 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 Expanded Net Energy Charge (ENEC) deferral balance, other ENEC-related assets and related financing costs.  In March 2013, APCo, WPCo and intervenors filed a settlement agreement with the WVPSC, which recommended the WVPSC authorize APCo to securitize $376 million plus upfront financing costs.  In September 2013, the WVPSC approved the settlement agreement.  The securitization bonds are expected to be issued in the fourth quarter of 2013.

 
24
 
Ohio Securitization of Regulatory Assets

In March 2013, the PUCO approved OPCo’s request to securitize the Deferred Asset Recovery Rider (DARR) balance.  The DARR was originally scheduled to be recovered through 2018 by a non-bypassable rider.  In August 2013, OPCo issued $267 million of Securitization Bonds to securitize the DARR balance.  As a result of the securitization, recovery through the DARR has ceased and has been replaced by the Deferred Asset Phase-in Rider which will recover the securitized transition assets over a period not to exceed eight years.

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 securitization bonds and debt of AEP Credit.  As of September 30, 2013, this contractually-defined percentage was 50.9%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  As of September 30, 2013, 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.

The term credit facility may be drawn upon until February 2014.  Repayments prior to maturity are permitted.  However, any amount that is repaid may not be re-borrowed and is a permanent reduction of the facility.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  As of September 30, 2013, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.50 per share in October 2013.  Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time.  Our income derives from our common stock equity in the earnings of our utility subsidiaries.  Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

We 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.

 
25
 
CASH FLOW

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

 
 
 
Nine Months Ended
 
 
 
September 30,
 
 
 
2013 
 
2012 
 
 
 
(in millions)
Cash and Cash Equivalents at Beginning of Period
 
$
 279 
 
$
 221 
Net Cash Flows from Operating Activities
 
 
 3,040 
 
 
 2,912 
Net Cash Flows Used for Investing Activities
 
 
 (2,520)
 
 
 (2,281)
Net Cash Flows Used for Financing Activities
 
 
 (652)
 
 
 (409)
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 (132)
 
 
 222 
Cash and Cash Equivalents at End of Period
 
$
 147 
 
$
 443 

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,
 
 
 
2013 
 
2012 
 
 
 
(in millions)
Net Income
 
$
 1,137 
 
$
 1,241 
Depreciation and Amortization
 
 
 1,310 
 
 
 1,353 
Other
 
 
 593 
 
 
 318 
Net Cash Flows from Operating Activities
 
$
 3,040 
 
$
 2,912 

Net Cash Flows from Operating Activities were $3 billion in 2013 consisting primarily of Net Income of $1.1 billion and $1.3 billion of noncash Depreciation and Amortization. Included in Other were $298 million of Asset Impairments related to Muskingum River Plant, Unit 5, Turk and Big Sandy Plants, partially offset by $157 million of Ohio capacity deferrals as a result of the PUCO's July 2012 approval of a capacity deferral mechanism.  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.  Deferred Income Taxes increased primarily due to provisions in the Taxpayer Relief Act of 2012 and an increase in tax/book temporary differences from operations.   Net cash flows for Accrued Taxes were a result of recording the estimated federal tax loss associated with tax/book temporary differences and the recognition of the tax benefit related to the U.K. Windfall Tax.

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.
 
 
26
 
Investing Activities
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended
 
 
 
September 30,
 
 
 
2013 
 
2012 
 
 
 
(in millions)
Construction Expenditures
 
$
 (2,481)
 
$
 (2,108)
Acquisitions of Nuclear Fuel
 
 
 (110)
 
 
 (13)
Acquisitions of Assets/Businesses
 
 
 (6)
 
 
 (89)
Insurance Proceeds Related to Cook Plant Fire
 
 
 72 
 
 
 - 
Proceeds from Sales of Assets
 
 
 14 
 
 
 13 
Other
 
 
 (9)
 
 
 (84)
Net Cash Flows Used for Investing Activities
 
$
 (2,520)
 
$
 (2,281)

Net Cash Flows Used for Investing Activities were $2.5 billion in 2013 primarily due to Construction Expenditures for environmental, distribution and transmission investments.

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.
 
Financing Activities
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended
 
 
 
September 30,
 
 
 
2013 
 
2012 
 
 
 
(in millions)
Issuance of Common Stock, Net
 
$
 61 
 
$
 64 
Issuance of Debt, Net
 
 
 43 
 
 
 262 
Dividends Paid on Common Stock
 
 
 (709)
 
 
 (687)
Other
 
 
 (47)
 
 
 (48)
Net Cash Flows Used for Financing Activities
 
$
 (652)
 
$
 (409)

Net Cash Flows Used for Financing Activities were $652 million in 2013.  Our net debt issuances were $43 million. The net issuances included issuances of $475 million of senior unsecured notes, $800 million draws on a $1 billion term credit facility, $305 million of pollution control bonds, $267 million of securitization bonds, $251 million of notes payable and other debt and an increase in short-term borrowing of $237 million offset by retirements of $1.8 billion of senior unsecured and other debt notes, $211 million of securitization bonds and $281 million of pollution control bonds.  We paid common stock dividends of $709 million.  See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows Used for Financing Activities were $409 million in 2012.  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.

In October 2013, I&M retired $37 million of Notes Payable related to DCC Fuel.

 
27
 
BUDGETED CONSTRUCTION EXPENDITURES

We forecast approximately $3.6 billion of construction expenditures excluding equity AFUDC and capitalized interest for 2013.  The total budgeted construction expenditures for 2013 remain unchanged but the table below shows updates to the allocation of expenditures as of September 30, 2013.  For 2014 and 2015, we forecast construction expenditures of $3.8 billion each year.  The projected increases are generally the result of required environmental investment to comply with Federal EPA rules and additional transmission spending.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  We expect to fund these construction expenditures through cash flows from operations and financing activities.  Generally, the subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged.  The 2013 updated estimated construction expenditures include generation, transmission and distribution related investments, as well as expenditures for compliance with environmental regulations as follows:

 
2013 
 
Budgeted
 
Construction
 
Expenditures
 
(in millions)
Environmental
$
 437 
Generation
 
 585 
Transmission
 
 1,455 
Distribution
 
 999 
Other
 
 121 
Total
$
 3,597 

OFF-BALANCE SHEET ARRANGEMENTS

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,
 
 
 
2013 
 
2012 
 
 
 
(in millions)
Rockport Plant, Unit 2 Future Minimum Lease Payments
 
$
 1,404 
 
$
 1,478 
Railcars Maximum Potential Loss from Lease Agreement
 
 
 19 
 
 
 25 

For complete information on each of these off-balance sheet arrangements, see the “Off-balance Sheet Arrangements” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2012 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 Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

 
28
 
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.  The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

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

Our Generation and Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM and MISO.  This segment is exposed to certain market risks as a marketer of wholesale and retail electricity.  These risks include commodity price risk, interest rate risk and credit risk.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

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, Energy Supply, 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 (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of our Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.  The Competitive Risk Committee consists of our Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, 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 respective committee.

 
29
 
The following table summarizes the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2012:

 
MTM Risk Management Contract Net Assets (Liabilities)
 
Nine Months Ended September 30, 2013
 
 
 
 
 
 
Generation
 
 
 
 
Utility
and
 
 
 
Operations
Marketing
Total
 
 
(in millions)
Total MTM Risk Management Contract Net Assets
 
 
 
 
 
 
 
 
 
as of December 31, 2012
$
 68 
 
$
 128 
 
$
 196 
(Gain) Loss from Contracts Realized/Settled During the Period and
 
 
 
 
 
 
 
 
 
Entered in a Prior Period
 
 (23)
 
 
 (16)
 
 
 (39)
Fair Value of New Contracts at Inception When Entered During the
 
 
 
 
 
 
 
 
 
Period (a)
 
 - 
 
 
 12 
 
 
 12 
Changes in Fair Value Due to Market Fluctuations During the
 
 
 
 
 
 
 
 
 
Period (b)
 
 1 
 
 
 15 
 
 
 16 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
 
 6 
 
 
 - 
 
 
 6 
Total MTM Risk Management Contract Net Assets
 
 
 
 
 
 
 
 
 
as of September 30, 2013
$
 52 
 
$
 139 
 
 
 191 
 
 
 
 
 
 
 
 
 
 
Commodity Cash Flow Hedge Contracts
 
 
 
 
 
 
 
 (2)
Interest Rate and Foreign Currency Cash Flow Hedge Contracts
 
 
 
 
 
 
 
 (2)
Fair Value Hedge Contracts
 
 
 
 
 
 
 
 (7)
Collateral Deposits
 
 
 
 
 
 
 
 21 
Total MTM Derivative Contract Net Assets as of September 30, 2013
 
 
 
 
 
 
$
 201 

(a)
Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  The contract prices are valued against market curves associated with the delivery location and delivery term.  A significant portion of the total volumetric position has been economically hedged.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)
Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets.

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

 
30
 
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, 2013, our credit exposure net of collateral to sub investment grade counterparties was approximately 8.3%, 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, 2013, 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
 
$
 634 
 
$
 - 
 
$
 634 
 
 
 2 
 
$
 297 
Split Rating
 
 
 1 
 
 
 1 
 
 
 - 
 
 
 - 
 
 
 - 
Noninvestment Grade
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1 
 
 
 - 
No External Ratings:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Internal Investment Grade
 
 
 75 
 
 
 - 
 
 
 75 
 
 
 3 
 
 
 35 
 
Internal Noninvestment Grade
 
 
 74 
 
 
 10 
 
 
 64 
 
 
 2 
 
 
 40 
Total as of September 30, 2013
 
$
 784 
 
$
 11 
 
$
 773 
 
 
 8 
 
$
 372 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total as of December 31, 2012
 
$
 807 
 
$
 13 
 
$
 794 
 
 
 7 
 
$
 338 

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, 2013, a near term typical change in commodity prices is not expected to materially impact 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, 2013
  
December 31, 2012
End
  
High
  
Average
  
Low
  
End
  
High
  
Average
  
Low
(in millions)
  
(in millions)
$
- 
  
$
1 
  
$
- 
  
$
- 
  
$
- 
  
$
1 
  
$
- 
  
$
- 

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

As our VaR calculation captures recent price movements, we also perform regular stress testing of the portfolio to understand our exposure to extreme price movements.  We employ a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which
 
 
31
 
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, 2013 and December 31, 2012, the estimated EaR on our debt portfolio for the following twelve months was $35 million and $42 million, respectively.

 
32
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2013 and 2012
 (in millions, except per-share and share amounts)
(Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
 
 
2013 
 
2012 
 
2013 
 
2012 
REVENUES
 
 
 
 
 
 
 
 
 
 
 
 
Utility Operations
 
$
 3,797 
 
$
 3,814 
 
$
 10,539 
 
$
 10,412 
Other Revenues
 
 
 379 
 
 
 342 
 
 
 1,045 
 
 
 920 
TOTAL REVENUES
 
 
 4,176 
 
 
 4,156 
 
 
 11,584 
 
 
 11,332 
EXPENSES
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
 
 1,168 
 
 
 1,180 
 
 
 3,107 
 
 
 3,137 
Purchased Electricity for Resale
 
 
 373 
 
 
 327 
 
 
 1,103 
 
 
 855 
Other Operation
 
 
 677 
 
 
 775 
 
 
 2,079 
 
 
 2,150 
Maintenance
 
 
 261 
 
 
 255 
 
 
 839 
 
 
 769 
Asset Impairments and Other Related Charges
 
 
 144 
 
 
 13 
 
 
 298 
 
 
 13 
Depreciation and Amortization
 
 
 447 
 
 
 470 
 
 
 1,310 
 
 
 1,353 
Taxes Other Than Income Taxes
 
 
 231 
 
 
 224 
 
 
 671 
 
 
 648 
TOTAL EXPENSES
 
 
 3,301 
 
 
 3,244 
 
 
 9,407 
 
 
 8,925 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
 
 875 
 
 
 912 
 
 
 2,177 
 
 
 2,407 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
 
 
Interest and Investment Income
 
 
 3 
 
 
 2 
 
 
 55 
 
 
 6 
Carrying Costs Income
 
 
 8 
 
 
 11 
 
 
 20 
 
 
 42 
Allowance for Equity Funds Used During Construction
 
 
 19 
 
 
 23 
 
 
 51 
 
 
 70 
Interest Expense
 
 
 (225)
 
 
 (233)
 
 
 (685)
 
 
 (697)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
 
 
 680 
 
 
 715 
 
 
 1,618 
 
 
 1,828 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 257 
 
 
 241 
 
 
 520 
 
 
 620 
Equity Earnings of Unconsolidated Subsidiaries
 
 
 11 
 
 
 14 
 
 
 39 
 
 
 33 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME
 
 
 434 
 
 
 488 
 
 
 1,137 
 
 
 1,241 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income Attributable to Noncontrolling Interests
 
 
 1 
 
 
 1 
 
 
 3 
 
 
 3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
 433 
 
$
 487 
 
$
 1,134 
 
$
 1,238 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
 
 
486,932,747 
 
 
484,979,543 
 
 
486,353,876 
 
 
484,437,875 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
 
 
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDERS
 
$
 0.89 
 
$
 1.00 
 
$
 2.33 
 
$
 2.55 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
 
 
487,258,905 
 
 
485,362,858 
 
 
486,792,914 
 
 
484,826,123 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
 
 
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDERS
 
$
 0.89 
 
$
 1.00 
 
$
 2.33 
 
$
 2.55 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CASH DIVIDENDS DECLARED PER SHARE
 
$
 0.49 
 
$
 0.47 
 
$
 1.45 
 
$
 1.41 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 39.
 
 
 
 
 
 
 
 
 
 
 
 

 
33
 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2013 and 2012
(in millions)
(Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
 
 
2013 
 
2012 
 
2013 
 
2012 
Net Income
 
$
 434 
 
$
 488 
 
$
 1,137 
 
$
 1,241 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $1 and $7 for the Three Months Ended
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30, 2013 and 2012, Respectively, and $7 and $4 for the Nine
 
 
 
 
 
 
 
 
 
 
 
 
 
Months Ended September 30, 2013 and 2012, Respectively
 
 
 (1)
 
 
 13 
 
 
 13 
 
 
 (8)
Securities Available for Sale, Net of Tax of $- and $- for the Three Months
 
 
 
 
 
 
 
 
 
 
 
 
 
Ended September 30, 2013 and 2012, Respectively, and $1 and $1 for the
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2013 and 2012, Respectively
 
 
 1 
 
 
 1 
 
 
 2 
 
 
 2 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $4
 
 
 
 
 
 
 
 
 
 
 
 
 
and $4 for the Three Months Ended September 30, 2013 and 2012,
 
 
 
 
 
 
 
 
 
 
 
 
 
Respectively, and $9 and $12 for the Nine Months Ended September 30,
 
 
 
 
 
 
 
 
 
 
 
 
 
2013 and 2012, Respectively
 
 
 7 
 
 
 7 
 
 
 16 
 
 
 22 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE INCOME
 
 
 7 
 
 
 21 
 
 
 31 
 
 
 16 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
 
 441 
 
 
 509 
 
 
 1,168 
 
 
 1,257 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Comprehensive Income Attributable to Noncontrolling Interests
 
 
 1 
 
 
 1 
 
 
 3 
 
 
 3 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDERS
 
$
 440 
 
$
 508 
 
$
 1,165 
 
$
 1,254 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 39.

 
34
 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 2013 and 2012
(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, 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 
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 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – DECEMBER 31, 2012
 
 506 
 
$ 
 3,289 
 
$ 
 6,049 
 
$ 
 6,236 
 
$ 
 (337)
 
$ 
 - 
 
$
 15,237 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Common Stock
 
 2 
 
 
 10 
 
 
 51 
 
 
 
 
 
 
 
 
 
 
 
 61 
Common Stock Dividends
 
 
 
 
 
 
 
 
 
 
 (706)
 
 
 
 
 
 (3)
 
 
 (709)
Other Changes in Equity
 
 
 
 
 
 
 
 5 
 
 
 
 
 
 
 
 
 1 
 
 
 6 
Net Income
 
 
 
 
 
 
 
 
 
 
 1,134 
 
 
 
 
 
 3 
 
 
 1,137 
Other Comprehensive Income
 
 
 
 
 
 
 
 
 
 
 
 
 
 31 
 
 
 
 
 
 31 
TOTAL EQUITY – SEPTEMBER 30, 2013
 
 508 
 
$ 
 3,299 
 
$ 
 6,105 
 
$ 
 6,664 
 
$ 
 (306)
 
$ 
 1 
 
$ 
 15,763 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 39.

 
35
 
 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2013 and December 31, 2012
(in millions)
(Unaudited)
 
 
 
 
 
 
 
 
 
September 30,
 
December 31,
 
 
2013 
 
2012 
CURRENT ASSETS
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 147 
 
$
 279 
Other Temporary Investments
 
 
 
 
 
 
 
(September 30, 2013 and December 31, 2012 Amounts Include $275 and $311, Respectively, Related to Transition Funding, Phase-in-Recovery Funding and EIS)
 
 
 288 
 
 
 324 
Accounts Receivable:
 
 
 
 
 
 
 
Customers
 
 
 657 
 
 
 685 
 
Accrued Unbilled Revenues
 
 
 164 
 
 
 195 
 
Pledged Accounts Receivable – AEP Credit
 
 
 982 
 
 
 856 
 
Miscellaneous
 
 
 107 
 
 
 171 
 
Allowance for Uncollectible Accounts
 
 
 (54)
 
 
 (36)
 
 
Total Accounts Receivable
 
 
 1,856 
 
 
 1,871 
Fuel
 
 
 748 
 
 
 844 
Materials and Supplies
 
 
 692 
 
 
 675 
Risk Management Assets
 
 
 171 
 
 
 191 
Regulatory Asset for Under-Recovered Fuel Costs
 
 
 81 
 
 
 88 
Margin Deposits
 
 
 72 
 
 
 76 
Prepayments and Other Current Assets
 
 
 262 
 
 
 241 
TOTAL CURRENT ASSETS
 
 
 4,317 
 
 
 4,589 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
Generation
 
 
 26,172 
 
 
 26,279 
 
Transmission
 
 
 10,256 
 
 
 9,846 
 
Distribution
 
 
 16,067 
 
 
 15,565 
Other Property, Plant and Equipment (Including Nuclear Fuel and Coal Mining)
 
 
 4,060 
 
 
 3,945 
Construction Work in Progress
 
 
 2,489 
 
 
 1,819 
Total Property, Plant and Equipment
 
 
 59,044 
 
 
 57,454 
Accumulated Depreciation and Amortization
 
 
 19,174 
 
 
 18,691 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
 
 39,870 
 
 
 38,763 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
Regulatory Assets
 
 
 5,038 
 
 
 5,106 
Securitized Transition Assets
 
 
 2,080 
 
 
 2,117 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 1,839 
 
 
 1,706 
Goodwill
 
 
 91 
 
 
 91 
Long-term Risk Management Assets
 
 
 314 
 
 
 368 
Deferred Charges and Other Noncurrent Assets
 
 
 1,414 
 
 
 1,627 
TOTAL OTHER NONCURRENT ASSETS
 
 
 10,776 
 
 
 11,015 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 54,963 
 
$
 54,367 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 39.
 
 
36
 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2013 and December 31, 2012
(dollars in millions)
(Unaudited)
 
 
 
 
 
 
 
 
 
September 30,
 
December 31,
 
 
2013 
 
2012 
CURRENT LIABILITIES
 
 
 
 
 
 
Accounts Payable
 
$
 1,044 
 
$
 1,169 
Short-term Debt:
 
 
 
 
 
 
 
Securitized Debt for Receivables - AEP Credit
 
 
 
 700 
 
 
 657 
 
Other Short-term Debt
 
 
 
 518 
 
 
 324 
 
 
Total Short-term Debt
 
 
 
 1,218 
 
 
 981 
Long-term Debt Due Within One Year
 
 
 
 
 
 
 
(September 30, 2013 and December 31, 2012 Amounts Include $433 and $367, Respectively, Related to Transition Funding, DCC Fuel, Phase-in-Recovery Funding and Sabine)
 
 
 1,366 
 
 
 2,171 
Risk Management Liabilities
 
 
 102 
 
 
 155 
Customer Deposits
 
 
 298 
 
 
 316 
Accrued Taxes
 
 
 590 
 
 
 747 
Accrued Interest
 
 
 219 
 
 
 269 
Regulatory Liability for Over-Recovered Fuel Costs
 
 
 14 
 
 
 47 
Other Current Liabilities
 
 
 841 
 
 
 968 
TOTAL CURRENT LIABILITIES
 
 
 5,692 
 
 
 6,823 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
Long-term Debt
 
 
 
 
 
 
 
(September 30, 2013 and December 31, 2012 Amounts Include $2,222 and $2,227, Respectively, Related to Transition Funding, DCC Fuel, Phase-in-Recovery Funding and Sabine)
 
 
 16,202 
 
 
 15,586 
Long-term Risk Management Liabilities
 
 
 182 
 
 
 214 
Deferred Income Taxes
 
 
 9,871 
 
 
 9,252 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 3,640 
 
 
 3,544 
Asset Retirement Obligations
 
 
 1,736 
 
 
 1,696 
Employee Benefits and Pension Obligations
 
 
 986 
 
 
 1,075 
Deferred Credits and Other Noncurrent Liabilities
 
 
 891 
 
 
 940 
TOTAL NONCURRENT LIABILITIES
 
 
 33,508 
 
 
 32,307 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 39,200 
 
 
 39,130 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
Commitments and Contingencies (Note 4)
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY
 
 
 
 
 
 
Common Stock – Par Value – $6.50 Per Share:
 
 
 
 
 
 
 
 
 
2013 
 
2012 
 
 
 
 
 
 
 
 
Shares Authorized
600,000,000 
 
600,000,000 
 
 
 
 
 
 
 
 
Shares Issued
507,594,430 
 
506,004,962 
 
 
 
 
 
 
 
(20,336,592 Shares were Held in Treasury as of September 30, 2013 and December 31, 2012)
 
 
 3,299 
 
 
 3,289 
Paid-in Capital
 
 
 6,105 
 
 
 6,049 
Retained Earnings
 
 
 6,664 
 
 
 6,236 
Accumulated Other Comprehensive Income (Loss)
 
 
 (306)
 
 
 (337)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY
 
 
 15,762 
 
 
 15,237 
 
 
 
 
 
 
 
Noncontrolling Interests
 
 
 1 
 
 
 - 
 
 
 
 
 
 
 
TOTAL EQUITY
 
 
 15,763 
 
 
 15,237 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 
$
 54,963 
 
$
 54,367 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 39.

 
37
 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2013 and 2012
(in millions)
(Unaudited)
 
 
 
 
 
Nine Months Ended September 30,
 
 
2013 
 
2012 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net Income
 
$
 1,137 
 
$
 1,241 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 1,310 
 
 
 1,353 
 
Deferred Income Taxes
 
 
 582 
 
 
 592 
 
Asset Impairments and Other Related Charges
 
 
 298 
 
 
 13 
 
Carrying Costs Income
 
 
 (20)
 
 
 (42)
 
Allowance for Equity Funds Used During Construction
 
 
 (51)
 
 
 (70)
 
Mark-to-Market of Risk Management Contracts
 
 
 29 
 
 
 70 
 
Amortization of Nuclear Fuel
 
 
 101 
 
 
 100 
 
Pension Contributions to Qualified Plan Trust
 
 
 - 
 
 
 (100)
 
Property Taxes
 
 
 191 
 
 
 181 
 
Fuel Over/Under-Recovery, Net
 
 
 38 
 
 
 133 
 
Deferral of Ohio Capacity Costs, Net
 
 
 (157)
 
 
 (22)
 
Change in Other Noncurrent Assets
 
 
 (35)
 
 
 (173)
 
Change in Other Noncurrent Liabilities
 
 
 16 
 
 
 119 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 4 
 
 
 (4)
 
 
Fuel, Materials and Supplies
 
 
 72 
 
 
 (169)
 
 
Accounts Payable
 
 
 (28)
 
 
 (135)
 
 
Accrued Taxes, Net
 
 
 (278)
 
 
 (130)
 
 
Other Current Assets
 
 
 (5)
 
 
 (28)
 
 
Other Current Liabilities
 
 
 (164)
 
 
 (17)
Net Cash Flows from Operating Activities
 
 
 3,040 
 
 
 2,912 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
Construction Expenditures
 
 
 (2,481)
 
 
 (2,108)
Change in Other Temporary Investments, Net
 
 
 53 
 
 
 19 
Purchases of Investment Securities
 
 
 (693)
 
 
 (745)
Sales of Investment Securities
 
 
 635 
 
 
 699 
Acquisitions of Nuclear Fuel
 
 
 (110)
 
 
 (13)
Acquisitions of Assets/Businesses
 
 
 (6)
 
 
 (89)
Insurance Proceeds Related to Cook Plant Fire
 
 
 72 
 
 
 - 
Proceeds from Sales of Assets
 
 
 14 
 
 
 13 
Other Investing Activities
 
 
 (4)
 
 
 (57)
Net Cash Flows Used for Investing Activities
 
 
 (2,520)
 
 
 (2,281)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Issuance of Common Stock, Net
 
 
 61 
 
 
 64 
Issuance of Long-term Debt
 
 
 2,087 
 
 
 1,600 
Commercial Paper and Credit Facility Borrowings
 
 
 17 
 
 
 21 
Change in Short-term Debt, Net
 
 
 240 
 
 
 (417)
Retirement of Long-term Debt
 
 
 (2,281)
 
 
 (904)
Commercial Paper and Credit Facility Repayments
 
 
 (20)
 
 
 (38)
Principal Payments for Capital Lease Obligations
 
 
 (53)
 
 
 (53)
Dividends Paid on Common Stock
 
 
 (709)
 
 
 (687)
Other Financing Activities
 
 
 6 
 
 
 5 
Net Cash Flows Used for Financing Activities
 
 
 (652)
 
 
 (409)
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 (132)
 
 
 222 
Cash and Cash Equivalents at Beginning of Period
 
 
 279 
 
 
 221 
Cash and Cash Equivalents at End of Period
 
$
 147 
 
$
 443 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 702 
 
$
 698 
Net Cash Paid (Received) for Income Taxes
 
 
 (64)
 
 
 (44)
Noncash Acquisitions Under Capital Leases
 
 
 53 
 
 
 46 
Construction Expenditures Included in Current Liabilities as of September 30,
 
 
 363 
 
 
 325 
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,
 
 
 - 
 
 
 43 
Noncash Assumption of Liabilities Related to Acquisitions
 
 
 - 
 
 
 56 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 39.

 
38
 

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

 
Page
 
Number
   
Significant Accounting Matters
   40
Comprehensive Income
   41
Rate Matters
   45
Commitments, Guarantees and Contingencies
   56
Acquisition and Impairments
   59
Benefit Plans
   60
Business Segments
   61
Derivatives and Hedging
   63
Fair Value Measurements
   70
Income Taxes
   77
Financing Activities
   79
Variable Interest Entities
   83
Sustainable Cost Reductions
   87

 
39
 

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, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013.  The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2012 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 26, 2013.

Earnings Per Share (EPS)

Basic earnings per common share is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period.  Diluted earnings per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.

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

 
 
 
Three Months Ended September 30,
 
 
 
2013 
 
2012 
 
 
 
(in millions, except per share data)
 
 
 
 
 
 
$/share
 
 
 
 
$/share
Earnings Attributable to AEP Common Shareholders
 
$
 433 
 
 
 
 
$
 487 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares Outstanding
 
 
 486.9 
 
$
 0.89 
 
 
 485.0 
 
$
 1.00 
Weighted Average Dilutive Effect of:
 
 
 
 
 
 
 
 
 
 
 
 
 
Stock Options
 
 
 - 
 
 
 - 
 
 
 0.1 
 
 
 - 
 
Restricted Stock Units
 
 
 0.4 
 
 
 - 
 
 
 0.3 
 
 
 - 
Weighted Average Number of Diluted Shares Outstanding
 
 
 487.3 
 
$
 0.89 
 
 
 485.4 
 
$
 1.00 

 
 
 
Nine Months Ended September 30,
 
 
 
2013 
 
2012 
 
 
 
(in millions, except per share data)
 
 
 
 
 
 
$/share
 
 
 
 
$/share
Earnings Attributable to AEP Common Shareholders
 
$
 1,134 
 
 
 
 
$
 1,238 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares Outstanding
 
 
 486.4 
 
$
 2.33 
 
 
 484.4 
 
$
 2.55 
Weighted Average Dilutive Effect of:
 
 
 
 
 
 
 
 
 
 
 
 
 
Stock Options
 
 
 - 
 
 
 - 
 
 
 0.1 
 
 
 - 
 
Restricted Stock Units
 
 
 0.4 
 
 
 - 
 
 
 0.3 
 
 
 - 
Weighted Average Number of Diluted Shares Outstanding
 
 
 486.8 
 
$
 2.33 
 
 
 484.8 
 
$
 2.55 

There were no antidilutive shares outstanding as of September 30, 2013 and 2012.

 
40
 
2.  COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2013.  All amounts in the following tables are presented net of related income taxes.

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2013
 
 
 
 
Cash Flow Hedges
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
Securities
 
Pension
 
 
 
 
 
 
Commodity
 
Foreign Currency
 
Available for Sale
 
and OPEB
 
Total
 
 
 
(in millions)
Balance in AOCI as of June 30, 2013
$
 1 
 
$
 (25)
 
$
 5 
 
$
 (294)
 
$
 (313)
Change in Fair Value Recognized in AOCI
 
 1 
 
 
 - 
 
 
 1 
 
 
 - 
 
 
 2 
Amounts Reclassified from AOCI
 
 (3)
 
 
 1 
 
 
 - 
 
 
 7 
 
 
 5 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Comprehensive Income
 
 (2)
 
 
 1 
 
 
 1 
 
 
 7 
 
 
 7 
Balance in AOCI as of September 30, 2013
$
 (1)
 
$
 (24)
 
$
 6 
 
$
 (287)
 
$
 (306)

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2013
 
 
 
 
Cash Flow Hedges
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
Securities
 
Pension
 
 
 
 
 
 
Commodity
 
Foreign Currency
 
Available for Sale
 
and OPEB
 
Total
 
 
 
(in millions)
Balance in AOCI as of December 31, 2012
$
 (8)
 
$
 (30)
 
$
 4 
 
$
 (303)
 
$
 (337)
Change in Fair Value Recognized in AOCI
 
 11 
 
 
 2 
 
 
 2 
 
 
 - 
 
 
 15 
Amounts Reclassified from AOCI
 
 (4)
 
 
 4 
 
 
 - 
 
 
 16 
 
 
 16 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Comprehensive Income
 
 7 
 
 
 6 
 
 
 2 
 
 
 16 
 
 
 31 
Balance in AOCI as of September 30, 2013
$
 (1)
 
$
 (24)
 
$
 6 
 
$
 (287)
 
$
 (306)

 
41
 
Reclassifications Out of Accumulated Other Comprehensive Income

The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2013.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs.  See Note 6 for additional details.

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
(Gain) Loss
 
 
 
 
Reclassified
 
 
 
 
from AOCI
Gains and Losses on Cash Flow Hedges
 
(in millions)
Commodity:
 
 
 
 
 
Utility Operations Revenues
 
$
 (1)
 
 
Other Revenues
 
 
 (3)
 
 
Purchased Electricity for Resale
 
 
 (1)
 
 
Property, Plant and Equipment
 
 
 - 
 
 
Regulatory Assets/(Liabilities), Net (a)
 
 
 - 
Subtotal - Commodity
 
 
 (5)
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
Interest Expense
 
 
 2 
Subtotal - Interest Rate and Foreign Currency
 
 
 2 
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 (3)
Income Tax (Expense) Credit
 
 
 (1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 (2)
 
 
 
 
Gains and Losses on Securities Available for Sale
 
 
 
Interest Income
 
 
 - 
Interest Expense
 
 
 - 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 - 
Income Tax (Expense) Credit
 
 
 - 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 - 
 
 
 
 
 
Amortization of Pension and OPEB
 
 
 
Prior Service Cost (Credit)
 
 
 (7)
Actuarial (Gains)/Losses
 
 
 18 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 11 
Income Tax (Expense) Credit
 
 
 4 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 7 
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 5 

 
42
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
(Gain) Loss
 
 
 
 
Reclassified
 
 
 
 
from AOCI
Gains and Losses on Cash Flow Hedges
 
(in millions)
Commodity:
 
 
 
 
 
Utility Operations Revenues
 
$
 (1)
 
 
Other Revenues
 
 
 (8)
 
 
Purchased Electricity for Resale
 
 
 3 
 
 
Property, Plant and Equipment
 
 
 - 
 
 
Regulatory Assets/(Liabilities), Net (a)
 
 
 - 
Subtotal - Commodity
 
 
 (6)
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
Interest Expense
 
 
 6 
Subtotal - Interest Rate and Foreign Currency
 
 
 6 
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 - 
Income Tax (Expense) Credit
 
 
 - 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 - 
 
 
 
 
Gains and Losses on Securities Available for Sale
 
 
 
Interest Income
 
 
 - 
Interest Expense
 
 
 - 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 - 
Income Tax (Expense) Credit
 
 
 - 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 - 
 
 
 
 
 
Amortization of Pension and OPEB
 
 
 
Prior Service Cost (Credit)
 
 
 (16)
Actuarial (Gains)/Losses
 
 
 41 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 25 
Income Tax (Expense) Credit
 
 
 9 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 16 
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 16 

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

 
43
 
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.  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)
 
 
 - 
 
 
 - 
 
 
 - 
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, 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 
Balance in AOCI as of September 30, 2012
 
$
 1 
 
$
 (32)
 
$
 (31)

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

 
44
 
The following tables provide details of changes in unrealized gains and losses related to Securities Available for Sale and the reasons for changes for the three and nine months ended September 30, 2012.  All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Securities Available for Sale
For the 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 Securities Available for Sale
For the 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 

3.  RATE MATTERS

As discussed in the 2012 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within our 2012 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 2013 and updates the 2012 Annual Report.
 
Regulatory Assets Not Yet Being Recovered
 
 
 
 
September 30,
 
December 31,
 
 
 
 
2013 
 
2012 
 
 
 
 
(in millions)
Noncurrent Regulatory Assets
 
 
 
 
 
 
Regulatory assets not yet being recovered pending future proceedings:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
 
Storm Related Costs
 
$
 22 
 
$
 23 
 
Economic Development Rider
 
 
 14 
 
 
 13 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 3 
 
 
 1 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
Storm Related Costs
 
 
 153 
 
 
 172 
 
Ormet Special Rate Recovery Mechanism
 
 
 32 
 
 
 5 
 
Virginia Environmental Rate Adjustment Clause
 
 
 28 
 
 
 29 
 
Expanded Net Energy Charge - Coal Inventory
 
 
 21 
 
 
 - 
 
Under-Recovered Capacity Costs
 
 
 16 
 
 
 - 
 
Mountaineer Carbon Capture and Storage Product Validation Facility
 
 
 14 
 
 
 14 
 
Litigation Settlement
 
 
 - 
 
 
 11 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 38 
 
 
 36 
Total Regulatory Assets Not Yet Being Recovered
 
$
 341 
 
$
 304 

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

 
45
 
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.  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 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 reduce OPCo’s net deferred fuel costs up to the total balance.  As of September 30, 2013, OPCo’s net deferred fuel balance was $467 million, excluding unrecognized equity carrying costs.  A decision from the Supreme Court of Ohio is pending.

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.  The 2009 SEET order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm.  In January 2013, the PUCO found there was not a need for the large solar farm.  The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project by the end of 2013.  In September 2013, a proposed second phase of OPCo’s gridSMART program was filed with the PUCO which included a recommended technology solution project to satisfy this PUCO directive.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  In October 2013, the PUCO issued an order on the 2010 SEET filing.  As a result, the PUCO ordered a $7 million refund of pretax earnings to customers.  OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis.  The PUCO approved OPCo’s requests to file the SEET for 2011 and 2012 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 or in 2012 for OPCo.  Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo.

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover deferred fuel costs in 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.  In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate.  The IEU and the Ohio Consumers’ Counsel also filed appeals, regarding the PUCO decision in the PIRR proceeding, at the Supreme Court of Ohio in November 2012 arguing principally that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo’s net deferred fuel balance up to the total balance.  These intervenor appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of September 30, 2013, could reduce carrying costs by $33 million including $17 million of unrecognized equity carrying costs.  A decision from the Supreme Court of Ohio is pending.

Management is unable to predict the outcome of the unresolved litigation discussed above.  Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition.

 
46
 
June 2012 – May 2015 ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015, which was generally upheld in rehearing orders in January and March 2013.

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 final orders in both the ESP and corporate separation cases and extending through May 2015.  The initiation of the auction is pending the issuance of an order by the PUCO in a separate docket.  The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning June 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015.  OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015.

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 up to $188.88/MW day.  The RPM price is approximately $33/MW day through May 2014.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.  As of September 30, 2013, OPCo’s incurred deferred capacity costs balance of $228 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR 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 recovery of deferred capacity costs.

In January and March 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order including the implementation of the RSR.  The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel.  In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP).  In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR.

In June 2013, intervenors in the CBP docket filed recommendations that include prospective rate reductions for capacity and non-energy FAC issues.  OPCo maintains that the August 2012 ESP order fixed OPCo’s non-energy generation rates through December 31, 2014 and ordered the application of a $188.88/MW day price for capacity for non-shopping customers effective January 1, 2015.  However, intervenors maintained that OPCo’s non-energy generation rates should be reduced prior to January 1, 2015 to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned (10% prior to June 2014 and 60% for the period June 1, 2014 through December 31, 2014).  An additional proposal to prospectively offset deferred capacity costs based upon the results of the energy-only auctions was not quantified and OPCo maintains that proposal should not be adopted in light of prior PUCO orders.  Hearings related to the CBP were held at the PUCO in June and July 2013.  A decision from the PUCO is pending. 

If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its deferred capacity costs, it could reduce future net income and cash flows and impact financial condition.

Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets at net book value to AEPGenCo.  AEPGenCo will also assume the associated generation liabilities.  In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.  A decision from the Supreme Court of Ohio is pending.  In October 2013, OPCo filed an application with the PUCO to amend the corporate separation plan by permitting OPCo to retain certain rights to purchase power from OVEC.

 
47
 
Also in October 2012, filings at the FERC were submitted related to corporate separation.  In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AEPGenCo.  Results of operations related to generation in Ohio will be largely determined by prevailing market conditions effective January 1, 2014.  See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.

Storm Damage Recovery Rider (SDRR)

In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates.  The SDRR seeks recovery of 2012 incremental storm distribution expenses over twelve months starting with the effective date of the SDRR as approved by the PUCO.  OPCo also requested approval of a weighted average cost of capital carrying charge if recovery of these costs did not begin prior to April 2013.  In May 2013, intervenors filed comments with various recommendations including reductions in the amount of storm costs recoverable up to the amount deferred, an extended recovery period, and an additional review of the storm costs including the allocation of costs to capital.  Hearings at the PUCO are scheduled for December 2013.  As of September 30, 2013, OPCo recorded $61 million in Regulatory Assets on the balance sheet related to 2012 storm damage.  If OPCo is not ultimately permitted to recover these storm costs, it could reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

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

In August 2012, intervenors filed an appeal 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 audit 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 with the use of a weighted average cost of capital (WACC).  The PUCO subsequently ruled that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes.  Hearings at the PUCO are scheduled for November 2013.  If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition.  See the 2009-2011 ESP section of the “Ohio Electric Security Plan Filing” related to the PUCO order in the PIRR proceeding.

Ormet

Ormet, a large aluminum company, has a contract through 2018 to purchase power from OPCo.  In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware.  In October 2013, following applications to the PUCO to amend Ormet’s power contract with OPCo, Ormet announced that they are unable to emerge from bankruptcy and are shutting down operations effective immediately.  Based upon previous PUCO rulings to provide rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider, except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet’s October and November 2012 power bills.  OPCo expects that any additional unpaid generation usage by Ormet will be recoverable as a regulatory asset through the Economic Development
 
 
48
 
Rider.  As of September 30, 2013, OPCo has recorded a regulatory asset of $32 million of Ormet amounts collectible through the Economic Development Rider as a result of these special rate recovery mechanisms and amounts unpaid by Ormet.

In the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future.  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.  The PUCO did not take any action on this request.  The intervenors raised the issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.

To the extent amounts referenced above are not recoverable, it could 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.  As of September 30, 2013, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order.  Intervenors have filed motions with the PUCO requesting OPCo refund all collected pre-construction costs 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 could 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 constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.  As of September 30, 2013, SWEPCo’s share of incurred construction expenditures for the Turk Plant was approximately $1.8 billion, including AFUDC and capitalized interest of $328 million and related transmission costs of $118 million.  As of September 30, 2013, a provision of $173 million has been recorded for costs incurred in excess of a Texas cost cap, resulting in total capitalized expenditures of $1.6 billion.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%).  Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN.  In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN.  The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market.

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 cash construction cost, excluding 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.  See the “2012 Texas Base Rate Case” disclosure below for a discussion of a PUCT order on the Texas capital cost cap.  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 March 2013, SWEPCo and the TIEC’s petitions for review at the Supreme Court of Texas were denied and in August 2013, SWEPCo and the TIEC’s motions for rehearing at the Supreme Court of Texas were denied.

 
49
 
If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Turk Plant, transmission lines or Welsh Plant, Unit 2, it could reduce future net income and cash flows and 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, primarily due to the Turk Plant, 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 (approximately 33%) of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation 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 and (c) included a return on and of the Stall Unit as of December 2011 and associated operation and maintenance costs.

In September 2012, an Administrative Law Judge (ALJ) 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.  In May 2013, the ALJ issued a proposal for decision recommending a rate increase but found SWEPCo imprudent for failing to cancel the Turk Plant in 2010.

The PUCT rejected the ALJ’s imprudence recommendation, but during a September 2013 open meeting, the PUCT stated that it would limit the recovery of the investment in the Turk Plant by imposing a Texas jurisdictional cost cap established in the recently concluded Certificate of Convenience and Necessity (CCN) case appeal discussed above (the Texas capital cost cap).  The PUCT also provided new details on how the cost cap would be applied.  In October 2013, the PUCT issued an order with the determination that the Turk Plant Texas capital cost cap also limited SWEPCo’s recovery of AFUDC in addition to its recovery of cash construction costs.  As a result of the determination that AFUDC was to be included in the cap, in the third quarter of 2013, SWEPCo recorded an additional pretax impairment of $111 million in Asset Impairments and Other Related Charges on the statement of income.  The order approved an annual rate increase of approximately $39 million based upon a return on common equity of 9.65%.  As a result of this approval, SWEPCo retroactively applied these rates back to the end of January 2013.  The approval also provided for the following:  (a) no disallowances to the existing book investment in the Stall Plant, and (b) the exclusion, until SWEPCo files and obtains approval of a Transmission Cost Recovery Rider, of the Turk Plant transmission line investment that was not in service at the end of the test year.  Additionally, the PUCT determined that it would defer consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.  As of September 30, 2013, the net book value of Welsh Plant, Unit 2 was $94 million, before cost of removal, including materials and supplies inventory and CWIP.  Requests for rehearing may be filed within 30 days of receipt of the PUCT order.  SWEPCo intends to file a motion for rehearing with the PUCT in late October 2013.

If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Turk Plant, transmission lines or Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant.  In February 2013, a settlement was filed and approved by the LPSC.  The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually.  The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund based on the staff review of the cost of service and the prudence review of the Turk Plant.  The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013.  In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant.  If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

 
50
 
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.  In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant.

APCo and WPCo Rate Matters

Plant Transfers

In October 2012, the AEP East Companies submitted several filings with the FERC regarding the transfer of certain generation plants within the AEP System.  See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.  In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant, comprising 1,647 MW of generating capacity presently owned by OPCo.  In June 2013, intervenors filed testimony with the WVPSC and made recommendations relating to APCo’s proposed asset transfers including the transfer of only one plant and the issuance of a Request for Proposals for any additional capacity and energy requirements.  Also in June 2013, the WVPSC staff filed testimony recommending the approval of the proposed asset transfers, with rate recognition to occur in a future base rate case, but limiting the liabilities to be transferred to the types and amounts reflected in the net book value of the assets.  In July 2013, the Virginia SCC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax.  The Virginia jurisdictional share of the disallowance is approximately $39 million.  The Virginia SCC also denied the proposed transfer of OPCo’s one-half interest in the Mitchell Plant to APCo.  APCo plans to pursue cost recovery of the transferred interest in the Amos Plant in Virginia in the 2014 biennial filing.  Management is currently evaluating the implications of this order while awaiting a final decision from the WVPSC.  Hearings were held at the WVPSC in July 2013.  In September 2013, a WVPSC staff brief advocated for the approval of the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo at the reduced value, for rate purposes, as approved by the Virginia SCC which could result in an additional $44 million disallowance related to the West Virginia and FERC jurisdictional shares of Amos Plant, Unit 3 and the denial of the proposed transfer of OPCo’s one-half interest in the Mitchell Plant to APCo.  This matter is currently pending before the WVPSC.  Any disallowance related to recovery of Amos Plant, Unit 3, as a result of Virginia SCC or WVPSC orders, would be recorded upon the transfer, expected in the fourth quarter of 2013.  If APCo and WPCo are not ultimately permitted to recover their incurred costs, it could reduce future net income and cash flows and impact financial condition.    

APCo IGCC Plant

As of September 30, 2013, 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 $10 million applicable to its Virginia jurisdiction.  If the costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs effective February 2014 over a one-year period.  In March 2013, the environmental RAC surcharge expired related to the collection of 2009 and 2010 environmental compliance costs.  In August 2013, a settlement agreement was submitted to the Virginia SCC which recommended approval of an environmental RAC to recover $38 million of the 2012 and 2011 environmental compliance costs.  In September 2013, the Hearing Examiner recommended the approval of the settlement agreement.  An order is expected from the Virginia SCC no later than November 2013.  APCo has deferred $28 million as of September 30, 2013 for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $10 million of unrecognized equity carrying costs.  If the Virginia SCC were to disallow any portion of the environmental RAC, it could reduce future net income and cash flows.

 
51
 
2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing

In March 2013, APCo filed with the Virginia SCC for an increase in its generation RAC revenues of $12 million for a total of $38 million annually to collect costs related to the Dresden Plant.  In August 2013, a settlement agreement was submitted to the Virginia SCC which recommended approval of an increase in the generation RAC to $37 million annually if the proposed merger of WPCo into APCo occurs by January 1, 2014 or an increase to $39 million if the proposed merger does not occur by January 1, 2014.  Per the settlement agreement, the generation RAC increase is to be effective no later than March 2014 for a period of one year at which time the component to collect an under-recovery of approximately $9 million will cease and the remaining component to recover on-going Dresden Plant costs will continue.  In October 2013, the Hearing Examiner recommended the approval of the settlement agreement.  An order is expected from the Virginia SCC no later than December 2013.  APCo has deferred $6 million as of September 30, 2013 for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $4 million of unrecognized equity carrying costs.  If the Virginia SCC were to disallow any portion of the generation RAC, it could reduce future net income and cash flows.

2013 West Virginia Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation which allows the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred ENEC balances and other ENEC-related assets.  In August 2012, APCo and WPCo filed a request with the WVPSC for a financing order to securitize a total of $422 million related to the December 2011 under-recovered ENEC deferral balance including other ENEC-related assets of $13 million and related future financing costs of $7 million.  Upon completion of the securitization, APCo would offset its current ENEC rates by an amount to recover the securitized balance over the securitization period.  In March 2013, APCo, WPCo and intervenors filed a settlement agreement with the WVPSC which recommended the WVPSC authorize APCo to securitize $376 million plus upfront financing costs.  In September 2013, the WVPSC approved the settlement agreement.  The securitization bonds are expected to be issued in the fourth quarter of 2013.

In April 2013, APCo and WPCo filed to keep total rates unchanged with a portion of the ENEC to be specifically identified for the amount to be securitized in accordance with the proposed securitization settlement agreement.  The remaining ENEC rate is proposed to include (a) the proposed transfer of certain generation facilities from OPCo and the APCo/WPCo merger, (b) construction surcharges and (c) ongoing ENEC costs.  In August 2013, the WVPSC approved a settlement that includes (a) a $56 million reduction in ENEC revenues, offset by a $6 million annual increase in construction surcharges, effective September 2013 and subject to true-up, (b) an agreement to file a base case no later than June 2014 and (c) the deferral of $21 million from the ENEC recovery balance with the ability to include that amount in the ENEC recovery balance upon reaching certain coal inventory levels at the Amos Plant.

As of September 30, 2013, APCo’s ENEC under-recovery balance of $281 million, net of 2012 and 2013 over-recovery, was recorded in Regulatory Assets on the balance sheet, excluding $2 million of unrecognized equity carrying costs and $14 million of other ENEC-related assets.

Virginia Storm Costs

In March 2013, due to the 2013 enactment of a Virginia law, APCo wrote off $30 million of previously deferred 2012 Virginia storm costs.  The change in law affected the test years to be included in APCo's next biennial Virginia base rate filing in March 2014 and the determination of how these costs are treated in the Virginia jurisdictional biennial earnings test for 2012 and 2013.  The estimated 2013 earnings component will be reviewed quarterly to determine if any storm costs can be deferred.  As of September 30, 2013, there were no deferrals of Virginia storm costs incurred in 2012 or 2013.  If this quarterly test allows APCo to defer previously expensed storm costs for future recovery, it could increase future net income and cash flows.

 
52
 
PSO Rate Matters

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES), Unit 4 in 2016 and additional environmental controls on NES, Unit 3 to continue operations through 2026.  As of September 30, 2013, the net book values of NES, Units 3 and 4 were $182 million and $101 million, respectively, before cost of removal, including materials and supplies inventory and CWIP.  In August 2013, the OCC dismissed PSO’s environmental compliance plan case without prejudice but will permit PSO to seek recovery in a future proceeding.  PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan.  If PSO is ultimately not permitted to fully recover its net book value of NES, Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%.  In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates from $85 million to $92 million.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed a request for reconsideration with the IURC, which was denied.  Also in March 2013, the OUCC filed an appeal of the order with the Indiana Court of Appeals.  In September 2013, the OUCC filed a brief on appeal that included objections to the inclusion of a prepaid pension asset in rate base, the use of an end-of-test-year amount for materials and supplies instead of a thirteen-month average and the application of an “outdated” capital structure.  If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of September 30, 2013, I&M has incurred $285 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery in a base rate case.  I&M was granted recovery through an LCM rider which will be determined by a proceeding in the fourth quarter of 2013 and semi-annual proceedings thereafter.  The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in its rates.   In October 2013, I&M filed an application with the IURC for LCM rider rates to be effective January 2014.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to certain projects effective January 2013 until these costs are included in rates.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

 
53
 
Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a Dry Sorbent Injection system.  The estimated cost in the application was $285 million, excluding AFUDC to be shared equally between I&M and AEGCo.  The application requested deferral treatment of any unrecovered carrying costs incurred during construction and incremental post in-service depreciation expense and operation and maintenance expenses until such costs are recognized and recovered in a rider.  I&M also requested cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism.

In July 2013, a settlement agreement was filed with the IURC.  The settlement agreement includes the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s ownership share.  The settlement agreement specifies that 80% of the recoverable I&M direct ownership share of CCT Project costs will be recovered through a Federal Mandate Rider with the remaining 20% deferred until rates are established in a subsequent rate case.  If the IURC approves the settlement agreement, I&M’s Indiana allocated share of the CCT Project costs received in the form of purchased power from AEGCo will be recovered in subsequent I&M rate cases.  A hearing was held at the IURC in August 2013 and a decision is expected by November 2013.  As of September 30, 2013, we have incurred costs of $93 million related to the CCT Project, including AFUDC.  If we are not ultimately permitted to recover our incurred costs, it could reduce future net income and cash flows.

Tanners Creek Plant, Units 1 - 4

In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations.  In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas.   I&M is currently recovering the net book value of Tanners Creek Plant, Units 1-4 in base rates, and plans to seek recovery of all of the plant’s retirement related costs in its next Indiana and Michigan base rate cases.  As of September 30, 2013, the combined net book value of Tanners Creek Plant, Units 1-4 was $342 million, before cost of removal, including materials and supplies inventory and CWIP.  If I&M is ultimately not permitted to fully recover its net book value of Tanners Creek Plant, Units 1-4, it could reduce future net income and cash flows and impact financial condition.

KPCo Rate Matters

Plant Transfer

In October 2012, the AEP East Companies submitted several filings with the FERC.  See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.  In December 2012, KPCo filed a request with the KPSC for approval to transfer at net book value to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by OPCo.  KPCo also requested costs related to the Big Sandy Plant, Unit 2 FGD project be established as a regulatory asset.  As of September 30, 2013, the net book value of Big Sandy, Unit 2 was $251 million, before cost of removal, including materials and supplies inventory and CWIP.  KPCo is currently seeking recovery of these costs with the KPSC.  In March 2013, KPCo issued a Request for Proposal (RFP) to purchase up to 250 MW of long-term capacity and energy to replace a portion of the capacity from the retirement of Big Sandy Plant, Unit 1.  In June 2013, KPCo filed the results of its RFP with the KPSC.

In July 2013, KPCo, Kentucky Industrial Utility Customers, Inc. (KIUC) and the Sierra Club filed a settlement agreement with the KPSC.  The settlement included the transfer of a one-half interest in the Mitchell Plant to KPCo at net book value on December 31, 2013 with the implementation of an Asset Transfer Rider to collect $44 million annually effective January 2014, subject to true-up.  The settlement also allows KPCo to retain any off-system sales margins above the $15.3 million annual level in base rates.  Additionally, the settlement included the authorization to record FGD project costs as a regulatory asset, the conversion of Big Sandy Plant, Unit 1 to natural gas and addressed potential greenhouse gas initiatives on the Mitchell Plant.  In October 2013, the KPSC issued an order approving a modified settlement agreement that included a limitation that the net book value of the Mitchell Plant transfer not exceed the amount to be determined by a WVPSC order, which is currently pending.  Additionally, the order rejected KPCo’s request to defer FGD project costs for Big Sandy, Unit 2.  Also in October 2013, KPCo filed
 
 
54
 
with the KPSC accepting and agreeing to be bound by the modifications to the settlement agreement.  As a result of this order, in the third quarter of 2013, KPCo recorded a pretax impairment of $33 million in Asset Impairments and Other Related Charges on the statement of income.

2013 Kentucky Base Rate Case

In June 2013, KPCo filed a request with the KPSC for an annual increase in base rates of $114 million based upon a return on common equity of 10.65% to be effective January 2014.  The proposed revenue increase includes cost recovery of the pending transfer of the one-half interest in the Mitchell Plant (780 MW).  In October 2013, the KPSC issued an order which modified and approved a settlement agreement relating to the proposed transfer of the one-half interest in the Mitchell Plant, in which KPCo agreed to withdraw this base rate case request.  KPCo intends to withdraw this base rate request following the resolution of any potential requests for rehearing or appeals of the KPSC order.  Assuming KPCo withdraws the base rate case, current base rates will remain in effect until at least May 2015.

FERC Rate Matters

Corporate Separation and Termination of Interconnection Agreement

In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations.  The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets to a new wholly-owned company, AEPGenCo.  The AEP East Companies also requested FERC approval to transfer at NBV  OPCo’s current two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests (780 MW each).  These transfers are proposed to be effective December 31, 2013.  In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AEPGenCo, the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo and the merger of APCo and WPCo.  In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo.  OPCo has contested the petition for rehearing, which remains pending before the FERC.  Similar asset transfer filings have been made at the KPSC, the Virginia SCC and the WVPSC.  See the “Plant Transfers” section of APCo and WPCo Rate Matters and the “Plant Transfer” section of KPCo Rate Matters.

Additionally, the AEP East Companies requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  Under the PCA, APCo, I&M and KPCo would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies.  Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.  Intervenors have opposed several of these filings.  The AEP East Companies responded to intervenor comments and filed a revised PCA at the FERC in March 2013.  The revised PCA included certain clarifying wording changes that have been agreed upon by intervenors.  A decision is pending at the FERC.

Additionally, FERC approval was sought for a power supply agreement between AEPGenCo and OPCo.  This agreement provides for AEPGenCo to supply capacity for OPCo’s switched and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that is not acquired through an auction from January 1, 2014 through December 31, 2014.

In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by recent orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation.  See the “Plant Transfers” section of APCo and WPCo Rate Matters and the “Plant Transfer” section of KPCo Rate Matters for a discussion of those orders.

If corporate separation is approved as filed, for any AEPGenCo generation not serving OPCo’s retail load, AEPGenCo’s results of operations will be largely determined by prevailing market conditions effective January 1, 2014.  If incurred costs are not ultimately recovered, it could reduce future net income and cash flows and impact financial condition.

 
55
 
4.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

We are subject to certain claims and legal actions arising in our ordinary course of business.  In addition, our business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation against us cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on our financial statements.  The Commitments, Guarantees and Contingencies note within our 2012 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 revolving credit facilities totaling $3.5 billion, under which we may issue up to $1.2 billion as letters of credit.  As of September 30, 2013, the maximum future payments for letters of credit issued under the revolving credit facilities were $185 million with maturities ranging from October 2013 to November 2014.

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 2014 to March 2015.

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 completed in 2010, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation.  As of September 30, 2013, SWEPCo has collected approximately $63 million through a rider for final mine closure and reclamation costs, of which $13 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $50 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 2012 Annual Report “Dispositions” section of Note 6.  As of September 30, 2013, there were no material liabilities recorded for any indemnifications.

 
56
 
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, 2013, the maximum potential loss for these lease agreements was approximately $20 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 assignment is 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 $14 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2013.

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 83% 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 $9 million and $10 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.  In May 2013, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court’s dismissal of the complaint.  The plaintiffs did not appeal to the U.S. Supreme Court.

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
 
 
57
 
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.  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 filed seeking further review in the U.S. Supreme Court.  In May 2013, the U.S. Supreme Court denied the plaintiffs’ request for review.
 
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 reserve is approximately $10 million.  As the remediation work is completed, I&M’s cost may change 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.

Nuclear Incident Insurance

Prior to April 2013, I&M carried insurance coverage for a nuclear or nonnuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion.  Effective April 2013, insurance coverage for a nonnuclear incident at the Cook Plant was reduced to $1.7 billion.  In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition.

OPERATIONAL CONTINGENCIES

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in Federal Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.  In October 2013, we filed a motion to dismiss the case.  We will continue to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

 
58
 
Natural Gas Markets Lawsuits

In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity.  AEP was dismissed from the case.  A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies.  AEP (or a subsidiary) is among the companies named as defendants in some of these cases.  We settled, received summary judgment or were dismissed from all of these cases.  The plaintiffs appealed the Nevada federal district court's dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit.  In April 2013, the appellate court reversed in part, and affirmed in part, the district court's orders in these cases.  The appellate court reversed the district court's holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases.  AEP filed a motion with the appellate court for rehearing on the issue of whether the district court had personal jurisdiction of AEP in the two referenced cases.  No decision has been rendered on that motion.  Defendants in these cases, including AEP, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue, which is pending.  We will continue to defend the cases.  We believe the provision we have is adequate.

5.  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.  This transaction also included goodwill of $15 million, intangible assets associated with sales contracts and customer accounts of $58 million and liabilities associated with supply contracts of $25 million.  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

2013

Turk Plant (Utility Operations segment)

In the third quarter of 2013, SWEPCo recorded a pretax write-off of $111 million in Asset Impairments and Other Related Charges on the statement of income related to AFUDC on the Turk Plant that was included in the Texas capital cost cap.  See the “2012 Texas Base Rate Case” section of Note 3.

Big Sandy Plant, Unit 2 FGD Project (Utility Operations segment)

In the third quarter of 2013, KPCo recorded a pretax write-off of $33 million in Asset Impairments and Other Related Charges on the statement of income primarily related to the Big Sandy Plant, Unit 2 FGD project.  See the “Plant Transfer” section of Note 3.

 
59
 
Muskingum River Plant, Unit 5 (Utility Operations segment)

In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including OPCo’s 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant.  Under the modification to the consent decree, OPCo has the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017.  In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, we re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project, which would have extended the useful life of MR5, is remote.  As a result, management completed an impairment analysis and concluded that MR5 was impaired.  Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit.  In the second quarter of 2013, OPCo recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory.  Management expects to retire the plant in 2015.

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 statement of income related to unrecoverable construction costs subject to the Texas capital costs cap portion of the Turk Plant.

6.  BENEFIT PLANS

Components of Net Periodic Benefit Cost

The following tables provide the components of our net periodic benefit cost (credit) for the plans for the three and nine months ended September 30, 2013 and 2012:

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in millions)
Service Cost
$
 17 
 
$
 19 
 
$
 5 
 
$
 12 
Interest Cost
 
 51 
 
 
 56 
 
 
 18 
 
 
 26 
Expected Return on Plan Assets
 
 (69)
 
 
 (80)
 
 
 (27)
 
 
 (26)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 - 
 
 
 1 
Amortization of Prior Service Cost (Credit)
 
 1 
 
 
 - 
 
 
 (17)
 
 
 (5)
Amortization of Net Actuarial Loss
 
 45 
 
 
 42 
 
 
 16 
 
 
 14 
Net Periodic Benefit Cost (Credit)
$
 45 
 
$
 37 
 
$
 (5)
 
$
 22 

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in millions)
Service Cost
$
 52 
 
$
 57 
 
$
 17 
 
$
 35 
Interest Cost
 
 152 
 
 
 167 
 
 
 53 
 
 
 78 
Expected Return on Plan Assets
 
 (208)
 
 
 (239)
 
 
 (80)
 
 
 (76)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 - 
 
 
 1 
Amortization of Prior Service Cost (Credit)
 
 2 
 
 
 - 
 
 
 (52)
 
 
 (14)
Amortization of Net Actuarial Loss
 
 137 
 
 
 117 
 
 
 48 
 
 
 43 
Net Periodic Benefit Cost (Credit)
$
 135 
 
$
 102 
 
$
 (14)
 
$
 67 

 
60
 
7.  BUSINESS SEGMENTS

As outlined in our 2012 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.

Our reportable segments and their related business activities are outlined 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.

 
61
 
The tables below present our reportable segment information for the three and nine months ended September 30, 2013 and 2012 and balance sheet information as of September 30, 2013 and December 31, 2012.  These amounts include certain estimates and allocations where necessary.

 
 
 
 
 
 
 
 
 
 
 
 
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, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
 3,788 
 
 
$ 
 8 
 
 
$
 125 
 
$
 251 
 
$
 4 
 
$
 - 
 
$
 4,176 
 
 
Other Operating Segments
 
 
 31 
 
 
 
 18 
 
 
 
 5 
 
 
 - 
 
 
 3 
 
 
 (57)
 
 
 - 
Total Revenues
 
$
 3,819 
 
 
$ 
 26 
 
 
$
 130 
 
$
 251 
 
$
 7 
 
$
 (57)
 
$
 4,176 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
$
 409 
 
 
$ 
 22 
 
 
$
 (1)
 
$
 4 
 
$
 - 
 
$
 - 
 
$
 434 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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)
Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
 10,520 
 
 
$
 18 
 
 
$
 365 
 
$
 671 
 
$
 10 
 
$
 - 
 
$
 11,584 
 
 
Other Operating Segments
 
 
 94 
 
 
 
 35 
 
 
 
 15 
 
 
 - 
 
 
 6 
 
 
 (150)
 
 
 - 
Total Revenues
 
$
 10,614 
 
 
$
 53 
 
 
$
 380 
 
$
 671 
 
$
 16 
 
$
 (150)
 
$
 11,584 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
$
 980 
 
 
$
 53 
 
 
$
 (12)
 
$
 15 
 
$
 101 
 
$
 - 
 
$
 1,137 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 

 
62
 
 
 
 
 
 
 
 
 
 
 
 
Nonutility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
 
Reconciling
 
 
 
 
 
 
 
Utility
 
 
Transmission
 
AEP River
 
and
 
All Other
 
 Adjustments
 
 
 
 
 
 
 
Operations
 
 
Operations
 
Operations
 
Marketing
 
(a)
 
(b)
 
 
Consolidated
 
 
 
 
(in millions)
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
 
$
 56,745 
 
 
$ 
 1,296 
 
$
 637 
 
$
 627 
 
$
 8 
 
$
 (269)
 
 
$
 59,044 
Accumulated Depreciation and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amortization
 
 
 18,791 
 
 
 
 7 
 
 
 182 
 
 
 268 
 
 
 8 
 
 
 (82)
 
 
 
 19,174 
Total Property, Plant and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Equipment - Net
 
$
 37,954 
 
 
$ 
 1,289 
 
$
 455 
 
$
 359 
 
$
 - 
 
$
 (187)
 
 
$
 39,870 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
 51,598 
 
 
$ 
 1,809 
 
$
 650 
 
$
 1,009 
 
$
 17,874 
 
$
 (17,977)
(c) 
 
$
 54,963 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nonutility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
 
Reconciling
 
 
 
 
 
 
 
Utility
 
 
Transmission
 
AEP River
 
and
 
All Other
 
 Adjustments
 
 
 
 
 
 
 
Operations
 
 
Operations
 
Operations
 
Marketing
 
(a)
 
(b)
 
 
Consolidated
 
 
 
 
(in millions)
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
 
$
 55,707 
 
 
$ 
 748 
 
$
 636 
 
$
 621 
 
$
 8 
 
$
 (266)
 
 
$
 57,454 
Accumulated Depreciation and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Amortization
 
 
 18,344 
 
 
 
 4 
 
 
 161 
 
 
 246 
 
 
 7 
 
 
 (71)
 
 
 
 18,691 
Total Property, Plant and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Equipment - Net
 
$
 37,363 
 
 
$ 
 744 
 
$
 475 
 
$
 375 
 
$
 1 
 
$
 (195)
 
 
$
 38,763 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
 51,477 
 
 
$ 
 1,216 
 
$
 670 
 
$
 1,005 
 
$
 17,191 
 
$
 (17,192)
(c) 
 
$
 54,367 

(a)
All Other includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
(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.

8.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

We are exposed to certain market risks as a major power producer and marketer of wholesale electricity, coal and emission allowances.  These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.  We manage these risks using derivative instruments.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

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 and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options.  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
 
 
63
 
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, 2013 and December 31, 2012:

Notional Volume of Derivative Instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
Volume
 
 
 
 
 
September 30,
 
December 31,
 
Unit of
 
 
2013 
 
2012 
 
Measure
Primary Risk Exposure
 
(in millions)
 
Commodity:
 
 
 
 
 
 
 
 
 
Power
 
 
 464 
 
 
 498 
 
MWhs
 
Coal
 
 
 6 
 
 
 10 
 
Tons
 
Natural Gas
 
 
 141 
 
 
 147 
 
MMBtus
 
Heating Oil and Gasoline
 
 
 5 
 
 
 6 
 
Gallons
 
Interest Rate
 
$
 201 
 
$
 235 
 
USD
 
 
 
 
 
 
 
 
 
 
Interest Rate and Foreign Currency
 
$
 820 
 
$
 1,199 
 
USD

Fair Value Hedging Strategies

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

Cash Flow Hedging Strategies

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

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

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.
 
 
64
 
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, 2013 and December 31, 2012 condensed balance sheets, we netted $5 million and $7 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $26 million and $50 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

 
65
 
The following tables represent the gross fair value impact of our derivative activity on our condensed balance sheets as of September 30, 2013 and December 31, 2012:

Fair Value of Derivative Instruments
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Risk Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in millions)
Current Risk Management Assets
 
$
 441 
 
$
 19 
 
$
 4 
 
$
 464 
 
$
 (293)
 
$
 171 
Long-term Risk Management Assets
 
 
 433 
 
 
 6 
 
 
 1 
 
 
 440 
 
 
 (126)
 
 
 314 
Total Assets
 
 
 874 
 
 
 25 
 
 
 5 
 
 
 904 
 
 
 (419)
 
 
 485 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
 389 
 
 
 23 
 
 
 1 
 
 
 413 
 
 
 (311)
 
 
 102 
Long-term Risk Management Liabilities
 
 
 301 
 
 
 4 
 
 
 13 
 
 
 318 
 
 
 (136)
 
 
 182 
Total Liabilities
 
 
 690 
 
 
 27 
 
 
 14 
 
 
 731 
 
 
 (447)
 
 
 284 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
 184 
 
$
 (2)
 
$
 (9)
 
$
 173 
 
$
 28 
 
$
 201 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Risk Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
Interest Rate
 
Assets/
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in millions)
Current Risk Management Assets
 
$
 589 
 
$
 32 
 
$
 3 
 
$
 624 
 
$
 (433)
 
$
 191 
Long-term Risk Management Assets
 
 
 528 
 
 
 5 
 
 
 1 
 
 
 534 
 
 
 (166)
 
 
 368 
Total Assets
 
 
 1,117 
 
 
 37 
 
 
 4 
 
 
 1,158 
 
 
 (599)
 
 
 559 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
 546 
 
 
 43 
 
 
 35 
 
 
 624 
 
 
 (469)
 
 
 155 
Long-term Risk Management Liabilities
 
 
 383 
 
 
 6 
 
 
 6 
 
 
 395 
 
 
 (181)
 
 
 214 
Total Liabilities
 
 
 929 
 
 
 49 
 
 
 41 
 
 
 1,019 
 
 
 (650)
 
 
 369 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
 188 
 
$
 (12)
 
$
 (37)
 
$
 139 
 
$
 51 
 
$
 190 

(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 primarily 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.
(c)
There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.

The table below presents our activity of derivative risk management contracts for the three and nine months ended September 30, 2013 and 2012:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three and Nine Months Ended September 30, 2013 and 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Location of Gain (Loss)
 
2013 
 
2012 
 
2013 
 
2012 
 
 
(in millions)
Utility Operations Revenues
 
$
 4 
 
$
 5 
 
$
 17 
 
$
 19 
Other Revenues
 
 
 9 
 
 
 20 
 
 
 39 
 
 
 28 
Regulatory Assets (a)
 
 
 - 
 
 
 2 
 
 
 (3)
 
 
 (35)
Regulatory Liabilities (a)
 
 
 (5)
 
 
 (14)
 
 
 (10)
 
 
 12 
Total Gain (Loss) on Risk
 
 
 
 
 
 
 
 
 
 
 
 
   Management Contracts
 
$
 8 
 
$
 13 
 
$
 43 
 
$
 24 

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

 
66
 
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, 2013, we recognized gains of $4 million and losses of $8 million, respectively, on our hedging instruments and offsetting losses of $4 million and gains of $8 million, respectively, on our long-term debt.  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, 2013 and 2012, hedge ineffectiveness was immaterial.

Accounting for Cash Flow Hedging Strategies

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

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on our condensed balance sheets, depending on the specific nature of the risk being hedged.  During the three and nine months ended September 30, 2013 and 2012, 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, 2013 and 2012, we designated heating oil and gasoline derivatives as cash flow hedges.

 
67
 
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, 2013 and 2012, 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, 2013, we did not designate any foreign currency derivatives as cash flow hedges.  During the three and nine months ended September 30, 2012, we designated foreign currency derivatives as cash flow hedges.

During the three and nine months ended September 30, 2013 and 2012, hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies disclosed above.

For 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, 2013 and 2012, see Note 2.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2013 and December 31, 2012 were:

Impact of Cash Flow Hedges on the Condensed Balance Sheet
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
 
 
 
Commodity
 
Currency
 
Total
 
 
 
 
(in millions)
Hedging Assets (a)
 
$
 9 
 
$
 - 
 
$
 9 
Hedging Liabilities (a)
 
 
 11 
 
 
 2 
 
 
 13 
AOCI Gain (Loss) Net of Tax
 
 
 (1)
 
 
 (24)
 
 
 (25)
Portion Expected to be Reclassified to Net
 
 
 
 
 
 
 
 
 
 
Income During the Next Twelve Months
 
 
 (2)
 
 
 (4)
 
 
 (6)
 
 
 
 
 
 
 
 
 
 
 
 
Impact of Cash Flow Hedges on the Condensed Balance Sheet
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
 
 
 
Commodity
 
Currency
 
Total
 
 
 
 
(in millions)
Hedging Assets (a)
 
$
 24 
 
$
 - 
 
$
 24 
Hedging Liabilities (a)
 
 
 36 
 
 
 37 
 
 
 73 
AOCI Gain (Loss) Net of Tax
 
 
 (8)
 
 
 (30)
 
 
 (38)
Portion Expected to be Reclassified to Net
 
 
 
 
 
 
 
 
 
 
Income During the Next Twelve Months
 
 
 (8)
 
 
 (4)
 
 
 (12)

 
(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, 2013, 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 was 27 months.

 
68
 
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.

When we use standardized master agreements, these agreements 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.

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 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, 2013 and December 31, 2012:

 
 
 
September 30,
 
December 31,
 
 
 
2013 
 
2012 
 
 
 
(in millions)
Liabilities for Derivative Contracts with Credit Downgrade Triggers
 
$
 3 
 
$
 7 
Amount of Collateral AEP Subsidiaries Would Have Been
 
 
 
 
 
 
 
Required to Post
 
 
 39 
 
 
 32 
Amount Attributable to RTO and ISO Activities
 
 
 38 
 
 
 31 

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, 2013 and December 31, 2012:

 
 
September 30,
 
December 31,
 
 
2013 
 
2012 
 
 
(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual
 
 
 
 
 
 
   Netting Arrangements
 
$
 341 
 
$
 469 
Amount of Cash Collateral Posted
 
 
 1 
 
 
 8 
Additional Settlement Liability if Cross Default Provision is Triggered
 
 
 258 
 
 
 328 

 
69
 
9.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

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

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 nonbinding 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.  Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs.  Some of these inputs may be internally developed or extrapolated and utilized 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.

 
70
 
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, 2013 and December 31, 2012 are summarized in the following table:

 
 
September 30, 2013
 
December 31, 2012
 
 
Book Value
 
Fair Value
 
Book Value
 
Fair Value
 
 
(in millions)
Long-term Debt
 
$
 17,568 
 
$
 19,316 
 
$
 17,757 
 
$
 20,907 

Fair Value Measurements of Other Temporary Investments

Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and Securities Available for Sale, including 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, 2013
 
 
 
 
 
 
Gross
 
Gross
 
Estimated
 
 
 
 
 
 
 Unrealized
 
Unrealized
 
 Fair
Other Temporary Investments
 
Cost
 
Gains
 
Losses
 
Value
 
 
 
 
(in millions)
Restricted Cash (a)
 
$
 188 
 
$
 - 
 
$
 - 
 
$
 188 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
Mutual Funds
 
 
 79 
 
 
 - 
 
 
 - 
 
 
 79 
Equity Securities - Mutual Funds
 
 
 13 
 
 
 8 
 
 
 - 
 
 
 21 
Total Other Temporary Investments
 
$
 280 
 
$
 8 
 
$
 - 
 
$
 288 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2012
 
 
 
 
 
 
Gross
 
Gross
 
Estimated
 
 
 
 
 
 
 Unrealized
 
Unrealized
 
 Fair
Other Temporary Investments
 
Cost
 
Gains
 
Losses
 
Value
 
 
 
 
(in millions)
Restricted Cash (a)
 
$
 241 
 
$
 - 
 
$
 - 
 
$
 241 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
Mutual Funds
 
 
 65 
 
 
 2 
 
 
 - 
 
 
 67 
Equity Securities - Mutual Funds
 
 
 10 
 
 
 6 
 
 
 - 
 
 
 16 
Total Other Temporary Investments
 
$
 316 
 
$
 8 
 
$
 - 
 
$
 324 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Primarily represents amounts held for the repayment of debt.

The following table provides the activity for our fixed income and equity securities within Other Temporary Investments for the three and nine months ended September 30, 2013 and 2012:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in millions)
Proceeds from Investment Sales
$
 - 
 
$
 - 
 
$
 - 
 
$
 - 
Purchases of Investments
 
 6 
 
 
 - 
 
 
 17 
 
 
 1 
Gross Realized Gains on Investment Sales
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Gross Realized Losses on Investment Sales
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 

 
71
 
As of September 30, 2013 and December 31, 2012, we had no Other Temporary Investments with an unrealized loss position.  As of September 30, 2013, fixed income securities were primarily debt based mutual funds with short and intermediate maturities.  Mutual funds may be sold and do not contain maturity dates.

For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2013 and 2012, see Note 2.

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 fixed income 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 fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized gains and other-than-temporary impairments from securities in the trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.  The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities.  Regulatory approval is required to withdraw decommissioning funds.

The following is a summary of nuclear trust fund investments as of September 30, 2013 and December 31, 2012:

 
 
 
September 30, 2013
 
December 31, 2012
 
 
 
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
 
$
 15 
 
$
 - 
 
$
 - 
 
$
 17 
 
$
 - 
 
$
 - 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 
 621 
 
 
 34 
 
 
 (3)
 
 
 648 
 
 
 58 
 
 
 (1)
 
Corporate Debt
 
 
 38 
 
 
 2 
 
 
 (2)
 
 
 35 
 
 
 5 
 
 
 (1)
 
State and Local Government
 
 
 244 
 
 
 1 
 
 
 - 
 
 
 270 
 
 
 1 
 
 
 (1)
 
  Subtotal Fixed Income Securities
 
 903 
 
 
 37 
 
 
 (5)
 
 
 953 
 
 
 64 
 
 
 (3)
Equity Securities - Domestic
 
 
 921 
 
 
 415 
 
 
 (81)
 
 
 736 
 
 
 285 
 
 
 (77)
Spent Nuclear Fuel and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning Trusts
 
$
 1,839 
 
$
 452 
 
$
 (86)
 
$
 1,706 
 
$
 349 
 
$
 (80)

 
72
 
The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2013 and 2012:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in millions)
Proceeds from Investment Sales
$
 250 
 
$
 182 
 
$
 635 
 
$
 699 
Purchases of Investments
 
 264 
 
 
 199 
 
 
 676 
 
 
 744 
Gross Realized Gains on Investment Sales
 
 4 
 
 
 2 
 
 
 16 
 
 
 7 
Gross Realized Losses on Investment Sales
 
 2 
 
 
 1 
 
 
 12 
 
 
 3 

The adjusted cost of fixed income securities was $866 million and $889 million as of September 30, 2013 and December 31, 2012, respectively.  The adjusted cost of equity securities was $506 million and $451 million as of September 30, 2013 and December 31, 2012, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2013 was as follows:

 
Fair Value of
 
Fixed Income
 
Securities
 
(in millions)
Within 1 year
$
 74 
1 year – 5 years
 
 378 
5 years – 10 years
 
 210 
After 10 years
 
 241 
Total
$
 903 

 
73
 
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, 2013 and December 31, 2012.  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, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
$
 14 
 
$
 1 
 
$
 - 
 
$
 132 
 
$
 147 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Temporary Investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash (a)
 
 173 
 
 
 7 
 
 
 - 
 
 
 8 
 
 
 188 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mutual Funds
 
 79 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 79 
Equity Securities - Mutual Funds (b)
 
 21 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 21 
Total Other Temporary Investments
 
 273 
 
 
 7 
 
 
 - 
 
 
 8 
 
 
 288 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (d)
 
 34 
 
 
 680 
 
 
 147 
 
 
 (399)
 
 
 462 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)
 
 2 
 
 
 22 
 
 
 - 
 
 
 (15)
 
 
 9 
Fair Value Hedges
 
 - 
 
 
 2 
 
 
 - 
 
 
 3 
 
 
 5 
De-designated Risk Management Contracts (e)
 
 - 
 
 
 - 
 
 
 - 
 
 
 9 
 
 
 9 
Total Risk Management Assets
 
 36 
 
 
 704 
 
 
 147 
 
 
 (402)
 
 
 485 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (f)
 
 6 
 
 
 - 
 
 
 - 
 
 
 9 
 
 
 15 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 - 
 
 
 621 
 
 
 - 
 
 
 - 
 
 
 621 
 
Corporate Debt
 
 - 
 
 
 38 
 
 
 - 
 
 
 - 
 
 
 38 
 
State and Local Government
 
 - 
 
 
 244 
 
 
 - 
 
 
 - 
 
 
 244 
 
 
Subtotal Fixed Income Securities
 
 - 
 
 
 903 
 
 
 - 
 
 
 - 
 
 
 903 
Equity Securities - Domestic (b)
 
 921 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 921 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 927 
 
 
 903 
 
 
 - 
 
 
 9 
 
 
 1,839 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 1,250 
 
$
 1,615 
 
$
 147 
 
$
 (253)
 
$
 2,759 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (d)
$
 40 
 
$
 613 
 
$
 24 
 
$
 (418)
 
$
 259 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)
 
 - 
 
 
 23 
 
 
 3 
 
 
 (15)
 
 
 11 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 2 
 
 
 - 
 
 
 - 
 
 
 2 
Fair Value Hedges
 
 - 
 
 
 9 
 
 
 - 
 
 
 3 
 
 
 12 
Total Risk Management Liabilities
$
 40 
 
$
 647 
 
$
 27 
 
$
 (430)
 
$
 284 

 
74
 


Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
$
 6 
 
$
 1 
 
$
 - 
 
$
 272 
 
$
 279 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Temporary Investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash (a)
 
 227 
 
 
 5 
 
 
 - 
 
 
 9 
 
 
 241 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mutual Funds
 
 67 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 67 
Equity Securities - Mutual Funds (b)
 
 16 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 16 
Total Other Temporary Investments
 
 310 
 
 
 5 
 
 
 - 
 
 
 9 
 
 
 324 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (g)
 
 47 
 
 
 938 
 
 
 131 
 
 
 (599)
 
 
 517 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)
 
 8 
 
 
 28 
 
 
 - 
 
 
 (12)
 
 
 24 
Fair Value Hedges
 
 - 
 
 
 2 
 
 
 - 
 
 
 2 
 
 
 4 
De-designated Risk Management Contracts (e)
 
 - 
 
 
 - 
 
 
 - 
 
 
 14 
 
 
 14 
Total Risk Management Assets
 
 55 
 
 
 968 
 
 
 131 
 
 
 (595)
 
 
 559 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (f)
 
 7 
 
 
 - 
 
 
 - 
 
 
 10 
 
 
 17 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 - 
 
 
 648 
 
 
 - 
 
 
 - 
 
 
 648 
 
Corporate Debt
 
 - 
 
 
 35 
 
 
 - 
 
 
 - 
 
 
 35 
 
State and Local Government
 
 - 
 
 
 270 
 
 
 - 
 
 
 - 
 
 
 270 
 
 
Subtotal Fixed Income Securities
 
 - 
 
 
 953 
 
 
 - 
 
 
 - 
 
 
 953 
Equity Securities - Domestic (b)
 
 736 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 736 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 743 
 
 
 953 
 
 
 - 
 
 
 10 
 
 
 1,706 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 1,114 
 
$
 1,927 
 
$
 131 
 
$
 (304)
 
$
 2,868 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (g)
$
 45 
 
$
 838 
 
$
 45 
 
$
 (636)
 
$
 292 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)
 
 - 
 
 
 48 
 
 
 - 
 
 
 (12)
 
 
 36 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 37 
 
 
 - 
 
 
 - 
 
 
 37 
Fair Value Hedges
 
 - 
 
 
 2 
 
 
 - 
 
 
 2 
 
 
 4 
Total Risk Management Liabilities
$
 45 
 
$
 925 
 
$
 45 
 
$
 (646)
 
$
 369 

(a)
Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties.  Level 1 and Level 2 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)
The September 30, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $1 million in 2013, ($3) million in periods 2014-2016 and ($4) million in periods 2017-2018;  Level 2 matures $4 million in 2013, $48 million in periods 2014-2016, $8 million in periods 2017-2018 and $7 million in periods 2019-2030;  Level 3 matures $6 million in 2013, $60 million in periods 2014-2016, $32 million in periods 2017-2018 and $25 million in periods 2019-2030.  Risk management commodity contracts are substantially comprised of power contracts.
(e)
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.
(f)
Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(g)
The December 31, 2012 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $9 million in 2013, ($3) million in periods 2014-2016 and ($4) million in periods 2017-2018;  Level 2 matures $16 million in 2013, $61 million in periods 2014-2016, $16 million in periods 2017-2018 and $7 million in periods 2019-2030;  Level 3 matures $18 million in 2013, $31 million in periods 2014-2016, $13 million in periods 2017-2018 and $24 million in periods 2019-2030.  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, 2013 and 2012.

 
75
 
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, 2013
 
Assets (Liabilities)
 
 
 
(in millions)
Balance as of June 30, 2013
 
$
 122 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
 
 (2)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
 
 
 
 
Relating to Assets Still Held at the Reporting Date (a)
 
 
 13 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
 
 (3)
Purchases, Issuances and Settlements (c)
 
 
 (8)
Transfers into Level 3 (d) (e)
 
 
 - 
Transfers out of Level 3 (e) (f)
 
 
 (2)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
 
 - 
Balance as of September 30, 2013
 
$
 120 

 
 
 
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) (e)
 
 
 (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
Nine Months Ended September 30, 2013
 
Assets (Liabilities)
 
 
 
(in millions)
Balance as of December 31, 2012
 
$
 86 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
 
 (9)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
 
 
 
 
Relating to Assets Still Held at the Reporting Date (a)
 
 
 32 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
 
 (3)
Purchases, Issuances and Settlements (c)
 
 
 (7)
Transfers into Level 3 (d) (e)
 
 
 18 
Transfers out of Level 3 (e) (f)
 
 
 (1)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
 
 4 
Balance as of September 30, 2013
 
$
 120 
 
76
 


 
 
 
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) (e)
 
 
 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 

 
(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)
Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
 
(f)
Represents existing assets or liabilities that were previously categorized as Level 3.
 
(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 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, 2013:

 
 
Fair Value
 
Valuation
 
Significant
 
Input/Range
 
Assets
 
Liabilities
Technique
Unobservable Input
 
Low
 
High
 
 
(in millions)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
 
$
 139 
 
$
 23 
 
Discounted Cash Flow 
 
Forward Market Price (a) 
 
$
 10.86 
 
$
 126.65 
 
 
 
 
 
 
 
 
 
 
Counterparty Credit Risk (b) 
 
 
374 
FTRs
 
 
 8 
 
 
 4 
 
Discounted Cash Flow 
 
Forward Market Price (a) 
 
 
 (11.44)
 
 
 13.11 
Total
 
$
 147 
 
$
 27 
 
 
 
 
 
 
 
 
 
 

(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.

10.  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

The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013.  The completion of the federal audit did not result in a material impact on net income, cash flows or financial condition.  Although the outcome of tax audits is uncertain, in our 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 materially impact net income.

 
77
 
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.  However, we believe that we have filed tax returns with positions that may be challenged by these tax authorities.  We believe 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.  We are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2008.

Uncertain Tax Positions

In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes.  We filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case.  As a result of the favorable U.S. Supreme Court decision, we recognized a tax benefit of $80 million, plus $43 million of pretax interest income in the second quarter of 2013.  The tax benefit and interest income resulted in an increase in net income of $108 million, but did not result in the receipt of cash during the second quarter of 2013.

The tax benefit associated with the U.K. Windfall Tax was reported as a $64 million unrecognized tax benefit as of December 31, 2012 and was included in the amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate.  Therefore, the related amounts reported as of December 31, 2012 have been reduced as of September 30, 2013, due to the recognition of the U.K. Windfall Tax benefit during the second quarter of 2013.

Federal Tax Regulations

In the third quarter of 2013, the U.S. Treasury Department issued final regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014.  The U.S. Treasury Department had previously issued guidance in the form of proposed and temporary regulations which was generally effective for tax years beginning in 2012, which was moved to tax years beginning in 2014 in November, 2012.  In addition, the IRS has issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry.  The impact of these final regulations is not material to net income, cash flows or financial condition.

State Tax Legislation

In the third quarter of 2013, 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% to 6.5% in 2014.  The enacted provisions will not materially impact net income, cash flows or financial condition.

 
78
 
11.  FINANCING ACTIVITIES

Long-term Debt

The following table details long-term debt outstanding as of September 30, 2013 and December 31, 2012:

Type of Debt
 
September 30, 2013
 
December 31, 2012
 
 
(in millions)
Senior Unsecured Notes
 
$
 11,705 
 
$
 12,712 
Pollution Control Bonds
 
 
 1,982 
 
 
 1,958 
Notes Payable
 
 
 425 
 
 
 427 
Securitization Bonds
 
 
 2,338 
 
 
 2,281 
Spent Nuclear Fuel Obligation (a)
 
 
 265 
 
 
 265 
Other Long-term Debt
 
 
 886 
 
 
 140 
Fair Value of Interest Rate Hedges
 
 
 (7)
 
 
 3 
Unamortized Discount, Net
 
 
 (26)
 
 
 (29)
Total Long-term Debt Outstanding
 
 
 17,568 
 
 
 17,757 
Long-term Debt Due Within One Year
 
 
 1,366 
 
 
 2,171 
Long-term Debt
 
$
 16,202 
 
$
 15,586 

 
(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 $309 million and $308 million as of September 30, 2013 and December 31, 2012, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets.
 
Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2013 are shown in the tables below:

 
 
 
 
 
Principal
 
 
Interest
 
 
Company
 
Type of Debt
 
Amount
 
 
Rate
 
Due Date
Issuances:
 
 
(in millions)
 
(%)
 
 
AEP
 
Other Long-term Debt
 
$
 200 
(a)
 
Variable
 
2015 
APCo
 
Pollution Control Bonds
 
 
 30 
 
 
3.25 
 
2018 
APCo
 
Pollution Control Bonds
 
 
 40 
 
 
3.25 
 
2018 
I&M
 
Notes Payable
 
 
 101 
 
 
Variable
 
2017 
I&M
 
 
Senior Unsecured Notes
 
 
 250 
 
 
3.20 
 
2023 
OPCo
 
Other Long-term Debt
 
 
 600 
(b)
 
Variable
 
2015 
OPCo
 
Pollution Control Bonds
 
 50 
 
 
Variable
 
2014 
OPCo
 
Pollution Control Bonds
 
 65 
 
 
Variable
 
2014 
OPCo
 
Securitization Bonds
 
 
 165 
 
 
0.96 
 
2018 
OPCo
 
Securitization Bonds
 
 
 102 
 
 
2.05 
 
2020 
 
 
 
 
 
 
 
 
 
 
 
 
Non-Registrant:
 
 
 
 
 
 
 
 
 
 
AEPTCo
 
Senior Unsecured Notes
 
 
 25 
 
 
4.83 
 
2043 
TCC
 
Other Long-term Debt
 
 
 75 
(c)
 
Variable
 
2016 
TCC
 
Pollution Control Bonds
 
 120 
 
 
4.00 
 
2030 
TNC
 
 
Other Long-term Debt
 
 
 75 
(d)
 
Variable
 
2016 
TNC
 
 
Senior Unsecured Notes
 
 
 125 
 
 
3.09 
 
2023 
TNC
 
 
Senior Unsecured Notes
 
 
 75 
 
 
4.48 
 
2043 
Total Issuances
 
 
 
$
 2,098 
(e)
 
 
 
 

 
79
 
 
 
 
 
 
Principal
 
 
Interest
 
 
Company
 
Type of Debt
 
Amount Paid
 
 
Rate
 
Due Date
Retirements and
 
 
 (in millions)
 
(%)
 
 
 
Principal Payments:
 
 
 
 
 
 
 
 
 
 
AEP
 
Other Long-term Debt
 
$
 200 
(a)
 
Variable
 
2015 
APCo
 
Pollution Control Bonds
 
 
 30 
 
 
4.85 
 
2013 
APCo
 
Pollution Control Bonds
 
 
 40 
 
 
4.85 
 
2013 
APCo
 
Senior Unsecured Notes
 
 
 275 
 
 
Variable
 
2013 
I&M
 
Notes Payable
 
 
 6 
 
 
5.44 
 
2013 
I&M
 
Notes Payable
 
 
 10 
 
 
4.00 
 
2014 
I&M
 
Notes Payable
 
 
 12 
 
 
Variable
 
2015 
I&M
 
Notes Payable
 
 
 15 
 
 
Variable
 
2016 
I&M
 
Notes Payable
 
 
 10 
 
 
2.12 
 
2016 
I&M
 
Notes Payable
 
 
 31 
 
 
Variable
 
2016 
I&M
 
Notes Payable
 
 
 8 
 
 
Variable
 
2017 
I&M
 
Other Long-term Debt
 
 
 4 
 
 
Variable
 
2015 
I&M
 
Other Long-term Debt
 
 
 1 
 
 
6.00 
 
2025 
I&M
 
Pollution Control Bonds
 
 
 40 
 
 
5.25 
 
2025 
OPCo
 
Pollution Control Bonds
 
 
 56 
 
 
5.10 
 
2013 
OPCo
 
Pollution Control Bonds
 
 
 50 
 
 
5.15 
 
2026 
OPCo
 
Pollution Control Bonds
 
 
 65 
 
 
4.90 
 
2037 
OPCo
 
Senior Unsecured Notes
 
 
 250 
 
 
5.50 
 
2013 
OPCo
 
Senior Unsecured Notes
 
 
 250 
 
 
5.50 
 
2013 
OPCo
 
Senior Unsecured Notes
 
 
 250 
 
 
5.75 
 
2013 
OPCo
 
Senior Unsecured Notes
 
 
 225 
 
 
6.38 
 
2033 
SWEPCo
 
Notes Payable
 
 
 3 
 
 
4.58 
 
2032 
 
 
 
 
 
 
 
 
 
 
 
 
Non-Registrant:
 
 
 
 
 
 
 
 
 
 
AEP Subsidiaries
 
Notes Payable
 
 
 5 
 
 
Variable
 
2017 
AEP Subsidiaries
 
Notes Payable
 
 
 2 
 
 
7.59 - 8.03
 
2026 
AEGCo
 
Senior Unsecured Notes
 
 
 7 
 
 
6.33 
 
2037 
TCC
 
Securitization Bonds
 
 
 76 
 
 
4.98 
 
2013 
TCC
 
Securitization Bonds
 
 
 67 
 
 
5.96 
 
2013 
TCC
 
Securitization Bonds
 
 
 42 
 
 
5.09 
 
2015 
TCC
 
Securitization Bonds
 
 
 26 
 
 
0.88 
 
2017 
TNC
 
Senior Unsecured Notes
 
 
 225 
 
 
5.50 
 
2013 
Total Retirements and
 
 
 
 
 
 
 
 
 
 
 
Principal Payments
 
 
 
$
 2,281 
 
 
 
 
 

 
(a)
Draw on a $1 billion term credit facility that was terminated in July 2013.
 
(b)
Draw on a $1 billion term credit facility due in May 2015.
 
(c)
Draw on a $100 million three-year revolving credit facility to be used for general corporate purposes.
 
(d)
Draw on a $75 million three-year revolving credit facility to be used for general corporate purposes.
 
(e)
Amount indicated on the statement of cash flows is net of issuance costs and premium or discount and will not tie to the total issuances.

In February 2013, we entered into a $1 billion term credit facility due in May 2015.  In July 2013, we terminated the $1 billion term credit facility.  Also in July 2013, AEPGenCo, APCo, KPCo and OPCo entered into a $1 billion term credit facility due in May 2015 to provide liquidity during the corporate separation process.  Upon entering into the new term credit facility, we repaid the $200 million Long-term Debt and OPCo subsequently borrowed $600 million under the new credit facility.  Under the credit facility, OPCo may assign borrowings to AEPGenCo upon the transfer of OPCo’s generation assets to AEPGenCo.  Subject to regulatory approval, AEPGenCo may further assign a portion of the borrowings to APCo and KPCo, not to exceed $500 million and $250 million, respectively, upon AEPGenCo’s subsequent transfer of certain of those generation assets to APCo and KPCo.

 
80
 
In October 2013, I&M retired $37 million of Notes Payable related to DCC Fuel.

As of September 30, 2013, trustees held on our behalf, $500 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.

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, 2013
 
December 31, 2012
 
 
 
Outstanding
 
Interest
 
Outstanding
 
Interest
Type of Debt
Amount
Rate (a)
 
Amount
Rate (a)
 
 
(in millions)
 
 
 
 
(in millions)
 
 
 
Securitized Debt for Receivables (b)
 
$
 700 
 
 0.23 
%
 
$
 657 
 
 0.26 
%
Commercial Paper
 
 
 518 
 
 0.31 
%
 
 
 321 
 
 0.42 
%
Line of Credit – Sabine (c)
 
 
 - 
 
 - 
%
 
 
 3 
 
 1.82 
%
Total Short-term Debt
 
$
 1,218 
 
 
 
 
$
 981 
 
 
 

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

Credit Facilities

For an additional discussion of credit facilities, see “Letters of Credit” section of Note 4.

 
81
 
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 2013, we amended our receivables securitization agreement.  The agreement provides a commitment of $700 million from bank conduits to purchase receivables.  We amended a commitment of $385 million to now expire in June 2014.  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,
 
 
 
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
(dollars in millions)
 
Effective Interest Rates on Securitization of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accounts Receivable
 
 
 0.23 
%
 
 0.26 
%
 
 0.23 
%
 
 0.26 
%
Net Uncollectible Accounts Receivable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Written Off
 
$
 12 
 
$
 8 
 
$
 26 
 
$
 21 
 

 
 
 
September 30,
 
December 31,
 
 
 
2013 
 
2012 
 
 
 
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
 
 
 
 
 
 
 
Less Uncollectible Accounts
 
$
 965 
 
$
 835 
Total Principal Outstanding
 
 
 700 
 
 
 657 
Delinquent Securitized Accounts Receivable
 
 
 60 
 
 
 37 
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable
 
 
 17 
 
 
 21 
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable
 
 
 266 
 
 
 316 

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.

 
82
 
12.  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, Ohio Phase-in-Recovery Funding and a protected cell of EIS.  In addition, we have not provided material financial or other support to Sabine, DCC Fuel, AEP Credit, Transition Funding, Ohio Phase-in-Recovery Funding and our protected cell of EIS 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, 2013 and 2012 were $41 million and $35 million, respectively, and for the nine months ended September 30, 2013 and 2012 were $125 million and $126 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on the condensed balance sheets.

I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI 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, 2013 and 2012 were $32 million and $23 million, respectively, and for the nine months ended September 30, 2013 and 2012 were $96 million and $82 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.  In October 2013, the lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC.  See the tables below for the classification of DCC Fuel’s assets and liabilities on the 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 the condensed balance sheets.  See “Securitized Accounts Receivable – AEP Credit” section of Note 11.

 
83
 
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 $2.1 billion and $2.3 billion as of September 30, 2013 and December 31, 2012, respectively, and are included in current and long-term debt on the condensed balance sheets.  Transition Funding has securitized transition assets of $1.9 billion and $2.1 billion as of September 30, 2013 and December 31, 2012, 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 the condensed balance sheets.

Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property.  Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant.  Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding.  The securitized bonds totaled $267 million as of September 30, 2013, and are included in current and long-term debt on the condensed balance sheet.  Ohio Phase-in-Recovery Funding has securitized assets of $137 million as of September 30, 2013, which is presented separately on the face of the condensed balance sheet.  The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO.  In August 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to OPCo or any other AEP entity.  OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs.  See the table below for the classification of Ohio Phase-in-Recovery Funding's assets and liabilities on the condensed balance sheet.

Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance.  EIS has multiple protected cells.  Neither AEP nor its subsidiaries have an equity investment in EIS.  The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance.  Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims.  Based on our control and the structure of the protected cell and EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate its assets and liabilities.  Our insurance premium expense to the protected cell for the three months ended September 30, 2013 and 2012 were $15 million and $16 million, respectively, and for the nine months ended September 30, 2013 and 2012 were $30 million and $31 million, respectively.  See the tables below for the classification of the protected cell’s assets and liabilities on the condensed balance sheets.  The amount reported as equity is the protected cell’s policy holders’ surplus.

 
84
 
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, 2013
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ohio
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TCC
 
Phase-in-
 
Protected
 
 
 
SWEPCo
 
I&M
 
 
 
 
Transition
 
Recovery
 
Cell
 
 
 
Sabine
DCC Fuel
AEP Credit
Funding
 
Funding
 
of EIS
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Assets
 
$
 65 
 
$
 155 
 
$
 972 
 
$
 197 
 
$
 12 
 
$
 146 
Net Property, Plant and Equipment
 
 
 160 
 
 
 181 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Other Noncurrent Assets
 
 
 56 
 
 
 79 
 
 
 1 
 
 
 1,989 
(a) 
 
 261 
(b) 
 
 4 
Total Assets
 
$
 281 
 
$
 415 
 
$
 973 
 
$
 2,186 
 
$
 273 
 
$
 150 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
 
$
 32 
 
$
 139 
 
$
 856 
 
$
 298 
 
$
 36 
 
$
 46 
Noncurrent Liabilities
 
 
 249 
 
 
 276 
 
 
 1 
 
 
 1,870 
 
 
 236 
 
 
 70 
Equity
 
 
 - 
 
 
 - 
 
 
 116 
 
 
 18 
 
 
 1 
 
 
 34 
Total Liabilities and Equity
 
$
 281 
 
$
 415 
 
$
 973 
 
$
 2,186 
 
$
 273 
 
$
 150 

(a)  Includes an intercompany item eliminated in consolidation of $84 million.
(b)  Includes an intercompany item eliminated in consolidation of $121 million.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2012
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TCC
 
 
 
 
 
SWEPCo
 
I&M
 
 
 
 
Transition
 
Protected Cell
 
 
Sabine
DCC Fuel
AEP Credit
Funding
 
of EIS
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Assets
 
$
 57 
 
$
 133 
 
$
 843 
 
$
 250 
 
$
 130 
Net Property, Plant and Equipment
 
 
 170 
 
 
 176 
 
 
 - 
 
 
 - 
 
 
 - 
Other Noncurrent Assets
 
 
 55 
 
 
 92 
 
 
 1 
 
 
 2,167 
(a) 
 
 4 
Total Assets
 
$
 282 
 
$
 401 
 
$
 844 
 
$
 2,417 
 
$
 134 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
 
$
 32 
 
$
 121 
 
$
 800 
 
$
 304 
 
$
 43 
Noncurrent Liabilities
 
 
 250 
 
 
 280 
 
 
 1 
 
 
 2,095 
 
 
 66 
Equity
 
 
 - 
 
 
 - 
 
 
 43 
 
 
 18 
 
 
 25 
Total Liabilities and Equity
 
$
 282 
 
$
 401 
 
$
 844 
 
$
 2,417 
 
$
 134 

                   (a)      Includes an intercompany item eliminated in consolidation of $89 million.

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, 2013 and 2012 were $21 million and $20 million, respectively, and for the nine months ended September 30, 2013 and 2012 were $53 million and $54 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 the condensed balance sheets.

 
85
 
Our investment in DHLC was:

 
 
September 30, 2013
 
December 31, 2012
 
 
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
 
 
 - 
 
 
 45 
 
 
 - 
 
 
 49 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Investment in DHLC
 
$
 9 
 
$
 54 
 
$
 9 
 
$
 58 

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.

In August 2012, the PJM board cancelled the PATH Project, our transmission joint venture with FirstEnergy, and removed it from the 2012 Regional Transmission Expansion Plan.  In November 2012, the FERC issued an order accepting AEP’s and FirstEnergy’s abandonment cost recovery filing which requested authority to recover prudently-incurred costs associated with the PATH Project, subject to refund based on the outcome of hearings and settlement procedures.

Our investment in PATH-WV was:

 
September 30, 2013
 
December 31, 2012
 
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
 
 14 
 
 
 14 
 
 
 12 
 
 
 12 
 
 
 
 
 
 
 
 
 
 
 
 
Total Investment in PATH-WV
$
 33 
 
$
 33 
 
$
 31 
 
$
 31 

 
86
 
13.  SUSTAINABLE COST REDUCTIONS

In April 2012, we initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings.  We selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate our current employee benefit programs.  The process resulted in involuntary severances and was completed by the end of the first quarter of 2013.  The severance program provides two weeks of base pay for every year of service along with other severance benefits.

We recorded a charge of $47 million to Other Operation expense in 2012 primarily related to severance benefits as a result of the sustainable cost reductions initiative.  In addition, the sustainable cost reduction activity for the nine months ended September 30, 2013 is described in the following table:

 
 
Sustainable Cost
 
 
Reduction Activity
 
 
(in millions)
Balance as of December 31, 2012
 
$
 25 
Incurred
 
 
 16 
Settled
 
 
 (30)
Adjustments
 
 
 (9)
Balance as of September 30, 2013
 
$
 2 

These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income.  Approximately 95% of the expense was within the Utility Operations segment.  The remaining liability is included in Other Current Liabilities on the condensed balance sheets.  We do not expect additional costs to be incurred related to this initiative.


 
87
 


 
 
APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
 
 
 
88
 


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

EXECUTIVE OVERVIEW

Regulatory Activity

Plant Transfers and Termination of Interconnection Agreement

Based upon the PUCO’s approval of OPCo’s corporate separation plan in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations, transfer these assets to AEPGenCo and subsequently transfer, at net book value (NBV), OPCo’s current two-thirds ownership in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests.  In December 2012, APCo filed requests with the Virginia SCC and WVPSC for the approval of these plant transfers.

In April 2013, the FERC issued orders approving the merger of APCo and WPCo and approving the transfer of the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo, to be effective using the requested date of December 31, 2013.  In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo.  This issue remains pending before the FERC.  In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.  A decision from the Supreme Court of Ohio is pending.  In July 2013, the Virginia SCC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax.  Additionally, the Virginia SCC denied the proposed transfer of OPCo’s one-half interest in the Mitchell Plant to APCo.  APCo plans to pursue cost recovery of the transferred interest in the Amos Plant in Virginia in the 2014 biennial filing.  Management is currently evaluating the implications of this order while awaiting a final decision from WVPSC.  Hearings in the plant transfer case were held at the WVPSC in July 2013.  In September 2013, a WVPSC staff brief advocated for the approval of the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo, also at a reduced amount for rate purposes, and the denial of the proposed transfer of OPCo’s one-half interest in the Mitchell Plant to APCo.  Any disallowance related to recovery of Amos Plant, Unit 3, as a result of Virginia SCC or WVPSC orders, would be recorded upon the transfer, expected in the fourth quarter of 2013.  See the “Plant Transfers” section of APCo Rate Matters in Note 3.
 
Additionally, the AEP East Companies requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  Under the PCA, APCo would be individually responsible for planning its capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies.  In March 2013, a revised PCA was filed at the FERC that included certain clarifying wording changes agreed upon by intervenors.  A decision is pending at the FERC.  See the “Corporate Separation and Termination of Interconnection Agreement” section of Note 3.

In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by recent orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation.  See the “Plant Transfers” section of APCo Rate Matters in Note 3 for a discussion of the Virginia SCC order.

If APCo experiences decreases in revenues or is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs effective February 2014 over a one-year period.  In August 2013, a settlement agreement was submitted to the Virginia SCC.  In September 2013, the Hearing Examiner recommended the approval of the settlement agreement.  An order is expected from the Virginia SCC no later than November 2013.  APCo has deferred $28 million as of September 30, 2013 for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $10 million of unrecognized equity carrying costs.  
 
 
89
 
If the Virginia SCC were to disallow any portion of the environmental RAC, it could reduce future net income and cash flows.  See “2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing” section of Note 3.

2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing

In March 2013, APCo filed with the Virginia SCC for an increase in its generation RAC revenues of $12 million for a total of $38 million annually to collect costs related to the Dresden Plant.  In August 2013, a settlement agreement was submitted to the Virginia SCC.  Per the settlement agreement, the generation RAC increase is to be effective no later than March 2014 for a period of one year at which time the component to collect an under-recovery will cease and the remaining component to recover on-going Dresden Plant costs will continue.  In October 2013, the Hearing Examiner recommended the approval of the settlement agreement.  An order is expected from the Virginia SCC no later than December 2013.  APCo has deferred $6 million as of September 30, 2013 for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $4 million of unrecognized equity carrying costs.  If the Virginia SCC were to disallow any portion of the generation RAC, it could reduce future net income and cash flows.  See “2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing” section of Note 3.

Securitization of Regulatory 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 Expanded Net Energy Charge (ENEC) deferral balance, other ENEC-related assets and related financing costs.  In March 2013, APCo, WPCo and intervenors filed a settlement agreement with the WVPSC, which recommended the WVPSC authorize APCo to securitize $376 million plus upfront financing costs.  In September 2013, the WVPSC approved the settlement agreement.  The securitization bonds are expected to be issued in the fourth quarter of 2013.  See the “2013 West Virginia Expanded Net Energy Charge (ENEC) Filing” section of Note 3.

WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting authority to merge WPCo into APCo.  In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC and in April 2013, the FERC approved the merger.  Also in December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval of the transfers at NBV to APCo of OPCo’s two-thirds interest in Amos Plant, Unit 3 and OPCo’s one-half interest in the Mitchell Plant.  In June 2013, the WVPSC issued an order consolidating the merger case with APCo’s plant asset transfer case.  Also in June 2013, WVPSC staff filed testimony that included a recommendation that the WVPSC approve the proposed merger.  Hearings were held at the WVPSC in July 2013.  These matters are pending before the WVPSC.  In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of OPCo’s one-half interest in the Mitchell Plant to APCo.  Although the Virginia SCC authorized the merger of WPCo into APCo, denial of the Mitchell Plant ownership transfer means there will be insufficient generation to serve the merged company.  Management intends to review the feasibility of the merger once the WVPSC issues an order in the consolidated cases.  See the “Plant Transfers” and “WPCo Merger with APCo” sections of APCo Rate Matters in Note 3.

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 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 161.  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 230 for additional discussion of relevant factors.

 
90
 
RESULTS OF OPERATIONS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
KWh Sales/Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summary of KWh Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 2,613 
 
 
 2,741 
 
 
 8,870 
 
 
 8,375 
 
Commercial
 
 1,788 
 
 
 1,804 
 
 
 5,147 
 
 
 5,112 
 
Industrial
 
 2,522 
 
 
 2,712 
 
 
 7,765 
 
 
 8,018 
 
Miscellaneous
 
 203 
 
 
 202 
 
 
 618 
 
 
 604 
Total Retail (a)
 
 7,126 
 
 
 7,459 
 
 
 22,400 
 
 
 22,109 
 
 
 
 
 
 
 
 
 
 
 
 
Wholesale
 
 3,132 
 
 
 2,745 
 
 
 7,201 
 
 
 5,618 
 
 
 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 10,258 
 
 
 10,204 
 
 
 29,601 
 
 
 27,727 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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,
 
 
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
(in degree days)
 
Actual - Heating (a)
 
 - 
 
 
 3 
 
 
 1,497 
 
 
 986 
 
Normal - Heating (b)
 
 3 
 
 
 3 
 
 
 1,408 
 
 
 1,443 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 727 
 
 
 892 
 
 
 1,115 
 
 
 1,336 
 
Normal - Cooling (b)
 
 815 
 
 
 817 
 
 
 1,182 
 
 
 1,178 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

 
91
 
Third Quarter of 2013 Compared to Third Quarter of 2012
 
 
 
 
 
 
 
 
 
 
Reconciliation of Third Quarter of 2012 to Third Quarter of 2013
 
Net Income
 
(in millions)
 
 
 
 
 
 
 
 
 
 
Third Quarter of 2012
 
 
 
 
$
 63 
 
 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
 
Retail Margins
 
 
 
 
 
 (19)
 
Off-system Sales
 
 
 
 
 
 (1)
 
Transmission Revenues
 
 
 
 
 
 6 
 
Other Revenues
 
 
 
 
 
 (8)
 
Total Change in Gross Margin
 
 
 
 
 
 (22)
 
 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 25 
 
Depreciation and Amortization
 
 
 
 
 
 2 
 
Carrying Costs Income
 
 
 
 
 
 (1)
 
Interest Expense
 
 
 
 
 
 3 
 
Total Change in Expenses and Other
 
 
 
 
 
 29 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 (7)
 
 
 
 
 
 
 
 
 
 
Third Quarter of 2013
 
 
 
 
$
 63 

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 $19 million primarily due to the following:
 
·
An $11 million decrease in weather-related usage primarily due to an 18% decrease in cooling degree days.
 
·
An $8 million net decrease in rates primarily due to the expiration of the Virginia Environmental Rate Adjustment Clause in March 2013.
 
·
A $5 million decrease in industrial usage.
 
These decreases were partially offset by:
 
·
A $5 million decrease in other variable electric generation expenses.
·
Transmission Revenues increased $6 million primarily due to increased Network Integration Transmission Service (NITS) revenue requirements.  These NITS revenues are offset in Other Operation and Maintenance expenses below.
·
Other Revenues decreased $8 million primarily due to resolution of contingencies related to pole attachments in the third quarter of 2013.  This decrease in Other Revenues is offset by a decrease in Other Operation and Maintenance expense detailed below.

 
92
 
Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses decreased $25 million primarily due to the following:
 
·
An $18 million decrease in uncollectible accounts expense as a result of:
  
   
·
A $13 million resolution of contingencies related to pole attachments in the third quarter of 2013.  This decrease in Other Operation and Maintenance expense is partially offset by a decrease in Other Revenues detailed above.
  
   
·
A $5 million provision for customer bankruptcy recorded in the third quarter of 2012.
  
 
·
A $4 million decrease associated with the deferral of transmission costs in accordance with Virginia Transmission Rate Adjustment Clause as allowed by the Virginia SCC.
  
 
·
A $4 million decrease in employee benefit expenses.
  
 
·
A $4 million decrease in transmission maintenance due to the June 2012 wind storms.
  
 
These decreases were partially offset by:
  
 
·
A $7 million increase in transmission expenses due to higher NITS expenses.  These expenses are offset in Transmission Revenues.
  
 
·
A $6 million increase in maintenance of overhead lines.
  
·
Interest Expense decreased $3 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·
Income Tax Expense increased $7 million primarily due to an increase in pretax book income and other book/tax differences which are accounted for on a flow-through basis.

 
93
 
Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012
 
 
 
 
 
 
 
 
 
 
 
 
Reconciliation of Nine Months Ended September 30, 2012 to Nine Months Ended September 30, 2013
 
Net Income
 
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2012
 
 
 
 
$
 201 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
 
 
 
Retail Margins
 
 
 
 
 
 15 
 
 
 
Off-system Sales
 
 
 
 
 
 (3)
 
 
 
Transmission Revenues
 
 
 
 
 
 11 
 
 
 
Other Revenues
 
 
 
 
 
 (7)
 
 
 
Total Change in Gross Margin
 
 
 
 
 
 16 
 
 
 
 
 
 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 (60)
 
 
 
Depreciation and Amortization
 
 
 
 
 
 (4)
 
 
 
Taxes Other Than Income Taxes
 
 
 
 
 
 (4)
 
 
 
Carrying Costs Income
 
 
 
 
 
 (11)
 
 
 
Other Income
 
 
 
 
 
 3 
 
 
 
Interest Expense
 
 
 
 
 
 10 
 
 
 
Total Change in Expenses and Other
 
 
 
 
 
 (66)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 12 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2013
 
 
 
 
$
 163 
 

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 $15 million primarily due to the following:
 
·
A $26 million increase in weather-related usage primarily due to a 52% increase in heating degree days.
 
·
A $14 million increase due to higher rates in Virginia and West Virginia.  For this increase, $7 million have a corresponding increase in Depreciation and Amortization expenses below.
 
These increases were partially offset by:
 
·
A $9 million deferral of additional wind purchase costs in the second quarter of 2012 as a result of the June 2012 Virginia SCC fuel factor order.
 
·
An $8 million increase in other variable electric generation expenses.
·
Transmission Revenues increased $11 million primarily due to increased NITS revenue requirements.  These NITS revenues are offset in Other Operation and Maintenance expenses below.
·
Other Revenues decreased $7 million primarily due to resolution of contingencies related to pole attachments in the third quarter of 2013.  This decrease in Other Revenues is offset by a decrease in Other Operation and Maintenance expense detailed below.

 
94
 
Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses increased $60 million primarily due to the following:
 
·
A $34 million increase in distribution maintenance expense primarily due to storms in January and June 2013.
  
 
·
A $30 million write-off in the first quarter of 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.
  
 
·
A $15 million increase in transmission expenses due to higher NITS expenses.  These expenses are partially offset in Transmission Revenues.
  
 
·
A $7 million increase in generation plant maintenance expenses due to Mountaineer Plant routine outages in 2013.
  
 
These increases were partially offset by:
  
 
·
A $12 million decrease in uncollectible accounts expense as a result of:
  
   
·
An $8 million resolution of contingencies related to pole attachments in the third quarter of 2013.  This decrease in Other Operation and Maintenance expense is offset by a decrease in Other Revenues detailed above.
  
   
·
A $5 million provision for customer bankruptcy recorded in the third quarter of 2012.
  
 
·
A $10 million decrease in employee benefit expenses.
  
·
Depreciation and Amortization expenses increased $4 million primarily due to the following:
 
·
An $8 million increase due to an increase in depreciable base.
  
 
·
A $3 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 $2 million increase due to the deferral of expenses in 2012 associated with the West Virginia portion of the Dresden Plant in accordance with a WPVSC order in APCo’s Expanded Net Energy Cost case.
  
 
These increases were partially offset by:
  
 
·
A $10 million decrease in amortization as a result of the cessation of the Virginia Environmental and Reliability surcharge and the Virginia Environmental Rate Adjustment Clause in January 2013 and March 2013, respectively.
  
·
Taxes Other Than Income Taxes increased $4 million primarily due to an increase in real and personal property tax amortization.
·
Carrying Costs Income decreased $11 million primarily due to an increased recovery of Virginia environmental costs in new base rates as approved by the Virginia SCC in late January 2012 and decreased carrying charges related to the Dresden Plant.
·
Interest Expense decreased $10 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·
Income Tax Expense decreased $12 million primarily due to a decrease in pretax book income partially offset by the recording of state income tax adjustments.

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 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, 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 230 for a discussion of accounting pronouncements.

 
95
 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
  
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
  
For the Three and Nine Months Ended September 30, 2013 and 2012
  
(in thousands)
  
(Unaudited)
  
 
  
 
  
Three Months Ended
    
Nine Months Ended
  
 
  
September 30,
    
September 30,
  
 
  
2013
    
2012
    
2013
    
2012
  
REVENUES
  
 
    
 
    
 
    
 
  
Electric Generation, Transmission and Distribution
   $ 756,606     $ 776,066     $ 2,299,587     $ 2,161,901  
Sales to AEP Affiliates
     90,558       84,940       241,311       216,284  
Other Revenues
     2,569       3,192       6,833       7,950  
TOTAL REVENUES
     849,733       864,198       2,547,731       2,386,135  
 
                                
EXPENSES
                                
Fuel and Other Consumables Used for Electric Generation
     207,442       241,448       575,902       609,985  
Purchased Electricity for Resale
     47,391       45,196       172,334       155,421  
Purchased Electricity from AEP Affiliates
     220,736       181,134       625,534       463,015  
Other Operation
     64,508       92,700       223,180       239,704  
Maintenance
     49,924       47,047       207,870       131,212  
Depreciation and Amortization
     84,513       86,636       255,656       252,188  
Taxes Other Than Income Taxes
     27,527       27,315       82,931       79,272  
TOTAL EXPENSES
     702,041       721,476       2,143,407       1,930,797  
 
                                
OPERATING INCOME
     147,692       142,722       404,324       455,338  
 
                                
Other Income (Expense):
                                
Interest Income
     334       332       2,134       1,034  
Carrying Costs Income
     2,793       3,950       6,029       17,202  
Allowance for Equity Funds Used During Construction
     826       443       2,809       960  
Interest Expense
     (47,375 )     (50,071 )     (143,707 )     (153,323 )
 
                                
INCOME BEFORE INCOME TAX EXPENSE
     104,270       97,376       271,589       321,211  
 
                                
Income Tax Expense
     41,645       34,185       108,554       120,377  
 
                                
NET INCOME
   $ 62,625     $ 63,191     $ 163,035     $ 200,834  
 
                                
The common stock of APCo is wholly-owned by AEP.
  
 
  
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
  

 
96
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
  
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
  
For the Three and Nine Months Ended September 30, 2013 and 2012
  
(in thousands)
  
(Unaudited)
  
 
  
 
    
 
    
 
    
 
  
 
     Three Months Ended       Nine Months Ended  
 
     September 30,       September 30,  
 
  
2013
    
2012
    
2013
    
2012
  
Net Income
   $ 62,625     $ 63,191     $ 163,035     $ 200,834  
 
                                
OTHER COMPREHENSIVE INCOME, NET OF TAXES
                                
Cash Flow Hedges, Net of Tax of $12 and $925 for the Three Months Ended
                                
September 30, 2013 and 2012, Respectively, and $737 and $940 for the Nine
                                
Months Ended September 30, 2013 and 2012, Respectively
     22       1,719       1,369       1,746  
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $193
                                
and $484 for the Three Months Ended September 30, 2013 and 2012,
                                
Respectively, and $579 and $1,453 for the Nine Months Ended
                                
September 30, 2013 and 2012, Respectively
     359       899       1,075       2,698  
 
                                
TOTAL OTHER COMPREHENSIVE INCOME
     381       2,618       2,444       4,444  
 
                                
TOTAL COMPREHENSIVE INCOME
   $ 63,006     $ 65,809     $ 165,479     $ 205,278  
 
                                
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
  
 
 
97
 


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
  
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
  
COMMON SHAREHOLDER'S EQUITY
  
For the Nine Months Ended September 30, 2013 and 2012
  
(in thousands)
  
(Unaudited)
  
 
  
 
    
 
    
 
    
 
    
 
  
 
  
 
    
 
    
 
    
Accumulated
    
 
  
 
  
 
    
 
    
 
    
Other
    
 
  
 
  
Common
    
Paid-in
    
Retained
    
Comprehensive
    
 
  
 
  
Stock
    
Capital
    
Earnings
    
Income (Loss)
    
Total
  
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 )
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  
 
                                        
TOTAL COMMON SHAREHOLDER'S
                                        
EQUITY – DECEMBER 31, 2012
   $ 260,458     $ 1,573,752     $ 1,248,250     $ (29,898 )   $ 3,052,562  
 
                                        
Common Stock Dividends
                     (130,000 )             (130,000 )
Net Income
                     163,035               163,035  
Other Comprehensive Income
                             2,444       2,444  
TOTAL COMMON SHAREHOLDER'S
                                        
EQUITY – SEPTEMBER 30, 2013
   $ 260,458     $ 1,573,752     $ 1,281,285     $ (27,454 )   $ 3,088,041  
 
                                        
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
          

 
98
 


 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
ASSETS
 
September 30, 2013 and December 31, 2012
 
(in thousands)
 
(Unaudited)
 
 
 
 
 
 
 
September 30,
 
December 31,
 
 
 
2013 
 
2012 
 
CURRENT ASSETS
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 4,130 
 
$
 3,576 
 
Advances to Affiliates
 
 
 23,424 
 
 
 23,024 
 
Accounts Receivable:
 
 
 
 
 
 
 
 
Customers
 
 
 130,168 
 
 
 158,380 
 
 
Affiliated Companies
 
 
 83,218 
 
 
 96,213 
 
 
Accrued Unbilled Revenues
 
 
 46,592 
 
 
 70,825 
 
 
Miscellaneous
 
 
 1,744 
 
 
 1,344 
 
 
Allowance for Uncollectible Accounts
 
 
 (2,361)
 
 
 (6,087)
 
 
 
Total Accounts Receivable
 
 
 259,361 
 
 
 320,675 
 
Fuel
 
 
 177,586 
 
 
 185,813 
 
Materials and Supplies
 
 
 108,341 
 
 
 105,208 
 
Risk Management Assets
 
 
 24,550 
 
 
 30,960 
 
Accrued Tax Benefits
 
 
 42,735 
 
 
 50,032 
 
Regulatory Asset for Under-Recovered Fuel Costs
 
 
 48,880 
 
 
 74,906 
 
Prepayments and Other Current Assets
 
 
 15,986 
 
 
 18,690 
 
TOTAL CURRENT ASSETS
 
 
 704,993 
 
 
 812,884 
 
 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
 
Generation
 
 
 5,688,679 
 
 
 5,632,665 
 
 
Transmission
 
 
 2,066,088 
 
 
 2,042,144 
 
 
Distribution
 
 
 3,075,781 
 
 
 2,991,898 
 
Other Property, Plant and Equipment
 
 
 386,192 
 
 
 373,327 
 
Construction Work in Progress
 
 
 250,040 
 
 
 266,247 
 
Total Property, Plant and Equipment
 
 
 11,466,780 
 
 
 11,306,281 
 
Accumulated Depreciation and Amortization
 
 
 3,307,175 
 
 
 3,196,639 
 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
 
 8,159,605 
 
 
 8,109,642 
 
 
 
 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
 
Regulatory Assets
 
 
 1,339,713 
 
 
 1,435,704 
 
Long-term Risk Management Assets
 
 
 20,839 
 
 
 34,360 
 
Deferred Charges and Other Noncurrent Assets
 
 
 96,016 
 
 
 115,078 
 
TOTAL OTHER NONCURRENT ASSETS
 
 
 1,456,568 
 
 
 1,585,142 
 
 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 10,321,166 
 
$
 10,507,668 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
 
 
99
 
 
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
September 30, 2013 and December 31, 2012
 
(Unaudited)
 
 
 
 
 
 
 
September 30,
 
December 31,
 
 
 
2013 
 
2012 
 
 
 
 
(in thousands)
 
CURRENT LIABILITIES
 
 
 
 
 
 
 
Advances from Affiliates
 
$
 276,776 
 
$
 173,965 
 
Accounts Payable:
 
 
 
 
 
 
 
 
General
 
 
 141,492 
 
 
 195,203 
 
 
Affiliated Companies
 
 
 98,211 
 
 
 137,088 
 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 229,682 
 
 
 574,679 
 
Risk Management Liabilities
 
 
 11,641 
 
 
 16,698 
 
Customer Deposits
 
 
 66,377 
 
 
 67,339 
 
Deferred Income Taxes
 
 
 21,263 
 
 
 11,715 
 
Accrued Taxes
 
 
 66,994 
 
 
 74,967 
 
Accrued Interest
 
 
 58,381 
 
 
 51,442 
 
Other Current Liabilities
 
 
 88,687 
 
 
 110,657 
 
TOTAL CURRENT LIABILITIES
 
 
 1,059,504 
 
 
 1,413,753 
 
 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 3,198,235 
 
 
 3,127,763 
 
Long-term Risk Management Liabilities
 
 
 12,081 
 
 
 18,476 
 
Deferred Income Taxes
 
 
 1,992,385 
 
 
 1,928,683 
 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 627,360 
 
 
 607,680 
 
Employee Benefits and Pension Obligations
 
 
 194,237 
 
 
 204,207 
 
Deferred Credits and Other Noncurrent Liabilities
 
 
 149,323 
 
 
 154,544 
 
TOTAL NONCURRENT LIABILITIES
 
 
 6,173,621 
 
 
 6,041,353 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 7,233,125 
 
 
 7,455,106 
 
 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
 
Commitments and Contingencies (Note 4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
 
 
 
Common Stock – No Par Value:
 
 
 
 
 
 
 
 
Authorized – 30,000,000 Shares
 
 
 
 
 
 
 
 
Outstanding – 13,499,500 Shares
 
 
 260,458 
 
 
 260,458 
 
Paid-in Capital
 
 
 1,573,752 
 
 
 1,573,752 
 
Retained Earnings
 
 
 1,281,285 
 
 
 1,248,250 
 
Accumulated Other Comprehensive Income (Loss)
 
 
 (27,454)
 
 
 (29,898)
 
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 3,088,041 
 
 
 3,052,562 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
 10,321,166 
 
$
 10,507,668 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

 
100
 


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2013 and 2012
(in thousands)
(Unaudited)
 
 
 
 
 
 
Nine Months Ended September 30,
 
 
2013 
 
2012 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net Income
 
$
 163,035 
 
$
 200,834 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 255,656 
 
 
 252,188 
 
 
Deferred Income Taxes
 
 
 89,501 
 
 
 84,850 
 
 
Carrying Costs Income
 
 
 (6,029)
 
 
 (17,202)
 
 
Deferral of Storm Costs
 
 
 34,364 
 
 
 (57,638)
 
 
Allowance for Equity Funds Used During Construction
 
 
 (2,809)
 
 
 (960)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 9,409 
 
 
 10,284 
 
 
Property Taxes
 
 
 21,940 
 
 
 20,056 
 
 
Fuel Over/Under-Recovery, Net
 
 
 46,009 
 
 
 61,404 
 
 
Change in Other Noncurrent Assets
 
 
 (19,784)
 
 
 (35,501)
 
 
Change in Other Noncurrent Liabilities
 
 
 10,199 
 
 
 7,155 
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 62,363 
 
 
 94,528 
 
 
 
Fuel, Materials and Supplies
 
 
 5,094 
 
 
 (44,007)
 
 
 
Accounts Payable
 
 
 (76,665)
 
 
 (27,443)
 
 
 
Accrued Taxes, Net
 
 
 (726)
 
 
 (709)
 
 
 
Other Current Assets
 
 
 1,970 
 
 
 1,754 
 
 
 
Other Current Liabilities
 
 
 (14,820)
 
 
 12,128 
Net Cash Flows from Operating Activities
 
 
 578,707 
 
 
 561,721 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
Construction Expenditures
 
 
 (272,433)
 
 
 (323,866)
Change in Advances to Affiliates, Net
 
 
 (400)
 
 
 (759)
Other Investing Activities
 
 
 103 
 
 
 7,880 
Net Cash Flows Used for Investing Activities
 
 
 (272,730)
 
 
 (316,745)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
 
 69,346 
 
 
 339,396 
Change in Advances from Affiliates, Net
 
 
 102,811 
 
 
 (80,674)
Retirement of Long-term Debt – Nonaffiliated
 
 
 (345,021)
 
 
 (364,868)
Principal Payments for Capital Lease Obligations
 
 
 (4,049)
 
 
 (4,873)
Dividends Paid on Common Stock
 
 
 (130,000)
 
 
 (135,000)
Other Financing Activities
 
 
 1,490 
 
 
 301 
Net Cash Flows Used for Financing Activities
 
 
 (305,423)
 
 
 (245,718)
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 554 
 
 
 (742)
Cash and Cash Equivalents at Beginning of Period
 
 
 3,576 
 
 
 2,317 
Cash and Cash Equivalents at End of Period
 
$ 
 4,130 
 
$ 
 1,575 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$ 
 131,600 
 
$
 137,992 
Net Cash Paid (Received) for Income Taxes
 
 
 (3,746)
 
 
 10,870 
Noncash Acquisitions Under Capital Leases
 
 
 3,440 
 
 
 2,338 
Construction Expenditures Included in Current Liabilities as of September 30,
 
 
 43,802 
 
 
 59,041 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

 
101
 

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.

 
Page
 
Number
   
Significant Accounting Matters
   162
Comprehensive Income
   162
Rate Matters
   175
Commitments, Guarantees and Contingencies
   186
Benefit Plans
   191
Business Segments
   194
Derivatives and Hedging
   195
Fair Value Measurements
   208
Income Taxes
   220
Financing Activities
   221
Variable Interest Entities
   225
Sustainable Cost Reductions
   229
   

 
102
 
 
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES


 
103
 

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

EXECUTIVE OVERVIEW

Regulatory Activity

Termination of Interconnection Agreement

Based upon the PUCO’s approval of OPCo’s corporate separation plan in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations and transfer at net book value certain plants to APCo and KPCo.  Additionally, the AEP East Companies requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  Under the PCA, I&M would be individually responsible for planning its capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies.  In March 2013, a revised PCA was filed at the FERC that included certain clarifying wording changes agreed upon by intervenors.  A decision is pending at the FERC.  See the “Corporate Separation and Termination of Interconnection Agreement” section of Note 3.

In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by recent orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation.  See the “Plant Transfers” section of APCo Rate Matters in Note 3 for a discussion of the Virginia SCC order.

If I&M experiences decreases in revenues or increases in expenses as a result of changes to its relationship with affiliates and is unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%.  In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates to $92 million.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the order with the Indiana Court of Appeals.  In September 2013, the OUCC filed a brief on appeal that included objections to certain aspects of the rate case.  If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.  See the “2011 Indiana Base Rate Case” section of Note 3.

Cook Plant Life Cycle Management Project (LCM 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, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of September 30, 2013, I&M has incurred $285 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items which the IURC stated could be sought for recovery in a base rate case.  I&M was granted recovery through an LCM rider which will be determined by a proceeding in the fourth quarter of 2013 and semi-annual proceedings thereafter.  The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in its rates.  In October 2013, I&M filed an application with the IURC for LCM rider rates to be effective January 2014.

 
104
 
In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to certain projects effective January 2013 until these costs are included in rates.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON.  If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.  See “Cook Plant Life Cycle Management Project (LCM Project)” section of Note 3.

Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a Dry Sorbent Injection system.  The estimated cost in the application was $285 million, excluding AFUDC to be shared equally between I&M and AEGCo.  In July 2013, a settlement agreement was filed with the IURC.  The settlement agreement includes the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s ownership share of $129 million.  A hearing was held at the IURC in August 2013 and a decision is expected by November 2013.  As of September 30, 2013, I&M has incurred costs of $48 million related to the CCT Project, including AFUDC.  If I&M is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows.  See the “Rockport Plant Clean Coal Technology Project (CCT Project)” section of Note 3.

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 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 161.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in Federal Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.  In October 2013, management filed a motion to dismiss the case. Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230 for additional discussion of relevant factors.

 
105
 
RESULTS OF OPERATIONS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
KWh Sales/Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summary of KWh Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 1,487 
 
 
 1,652 
 
 
 4,365 
 
 
 4,438 
 
Commercial
 
 1,335 
 
 
 1,370 
 
 
 3,720 
 
 
 3,826 
 
Industrial
 
 1,914 
 
 
 1,887 
 
 
 5,611 
 
 
 5,684 
 
Miscellaneous
 
 16 
 
 
 16 
 
 
 51 
 
 
 54 
Total Retail (a)
 
 4,752 
 
 
 4,925 
 
 
 13,747 
 
 
 14,002 
 
 
 
 
 
 
 
 
 
 
 
 
Wholesale
 
 3,198 
 
 
 3,009 
 
 
 8,029 
 
 
 7,039 
 
 
 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 7,950 
 
 
 7,934 
 
 
 21,776 
 
 
 21,041 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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,
 
 
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
(in degree days)
 
Actual - Heating (a)
 
 2 
 
 
 19 
 
 
 2,552 
 
 
 1,803 
 
Normal - Heating (b)
 
 11 
 
 
 11 
 
 
 2,396 
 
 
 2,431 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 523 
 
 
 696 
 
 
 801 
 
 
 1,095 
 
Normal - Cooling (b)
 
 584 
 
 
 594 
 
 
 846 
 
 
 851 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

 
106
 
Third Quarter of 2013 Compared to Third Quarter of 2012
 
  
 
  
Reconciliation of Third Quarter of 2012 to Third Quarter of 2013
  
Net Income
  
(in millions)
  
 
  
 
  
Third Quarter of 2012
   $ 39  
 
        
Changes in Gross Margin:
        
Retail Margins
     14  
FERC Municipals and Cooperatives
     8  
Off-system Sales
     (4 )
Transmission Revenues
     5  
Total Change in Gross Margin
     23  
 
        
Changes in Expenses and Other:
        
Other Operation and Maintenance
     5  
Depreciation and Amortization
     (8 )
Taxes Other Than Income Taxes
     1  
Other Income
     6  
Interest Expense
     3  
Total Change in Expenses and Other
     7  
 
        
Income Tax Expense
     (11 )
 
        
Third Quarter of 2013
   $ 58  

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 $14 million primarily due to the following:
   
·
A $26 million increase due to rate increases in Indiana effective March 2013, higher PJM revenue and higher Indiana Demand Side Management (DSM) revenue.  The PJM and DSM increases were partially offset in expense items below.
   
The increase was partially offset by:
   
·
A $9 million decrease in weather-related usage primarily due to a decrease in cooling degree days.
 
·
Margins from FERC Municipal and Cooperatives increased $8 million primarily due to higher formula rates in 2013.
 
·
Margins from Off-system Sales decreased $4 million primarily due to lower physical sales margins,  reduced trading and marketing margins and true-up of prior period PJM expenses.
 
·
Transmission Revenues increased $5 million primarily due to higher PJM rates effective July 2013.

 
107
 
Expenses and Other and Income Tax Expense changed between years as follows:
 
 
·
Other Operation and Maintenance expenses decreased $5 million primarily due to the following:
     
·
A $7 million decrease in administrative and general operation expenses primarily related to employee benefit expenses.
  
     
·
A $5 million decrease in distribution expenses primarily due to higher storm restoration expenses in 2012.
  
     
These decreases were partially offset by:
  
     
·
A $4 million increase in transmission expenses primarily due to increased PJM expenses.
  
     
·
A $2 million increase in customer service expenses primarily due to higher DSM expenses.  The increase in DSM expenses was offset by a corresponding increase in Retail Margins discussed above.
  
 
·
Depreciation and Amortization expenses increased $8 million primarily due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant’s estimated life approved by the IURC effective March 2013.  The majority of the increase in depreciation for Tanners Creek Plant’s life is offset within Gross Margin.
 
·
Other Income increased $6 million primarily due to an increase in the equity component of AFUDC.
 
·
Income Tax Expense increased $11 million primarily due to an increase in pretax book income.
 
 
108
 
Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012
 
Reconciliation of Nine Months Ended September 30, 2012 to Nine Months Ended September 30, 2013
Net Income
(in millions)
 
 
 
 
 
Nine Months Ended September 30, 2012
 
$
 108 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
Retail Margins
 
 
 51 
 
FERC Municipals and Cooperatives
 
 
 28 
 
Off-system Sales
 
 
 (8)
 
Transmission Revenues
 
 
 1 
 
Other Revenues
 
 
 2 
 
Total Change in Gross Margin
 
 
 74 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
Other Operation and Maintenance
 
 
 (9)
 
Depreciation and Amortization
 
 
 (23)
 
Taxes Other Than Income Taxes
 
 
 (3)
 
Other Income
 
 
 14 
 
Interest Expense
 
 
 4 
 
Total Change in Expenses and Other
 
 
 (17)
 
 
 
 
 
 
Income Tax Expense
 
 
 (23)
 
 
 
 
 
 
Nine Months Ended September 30, 2013
 
$
 142 
 

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 $51 million primarily due to a rate increase in Indiana effective March 2013, higher PJM revenue and higher Indiana Demand Side Management (DSM) revenue.  The PJM and DSM increases were partially offset in expense items below.
 
·
Margins from FERC Municipal and Cooperatives increased $28 million primarily due to the annual true-up adjustment of formula rates to actual costs and higher formula rates for 2013.
 
·
Margins from Off-system Sales decreased $8 million primarily due to lower PJM capacity revenues, reduced trading and marketing margins and true-up of prior period PJM expenses.

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 $12 million increase in transmission expenses primarily due to increased PJM expenses.
   
·
A $7 million increase in steam maintenance expenses primarily due to Rockport Plant and Tanners Creek Plant outages in the first quarter of 2013.
   
·
A $5 million increase in customer service expenses primarily due to higher DSM expenses.  The increase in DSM expenses was offset by a corresponding increase in Retail Margins discussed above.
   
These increases were partially offset by:
   
·
An $11 million decrease in administrative and general operation expenses primarily related to employee benefit expenses.
 
·
Depreciation and Amortization expenses increased $23 million primarily due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant’s estimated life approved by the MPSC effective April 2012 and by the IURC effective March 2013.  The majority of the increase in depreciation for Tanners Creek Plant’s life is offset within Gross Margin.
 
·
Other Income increased $14 million primarily due to an increase in the equity component of AFUDC.
 
·
Interest Expense decreased $4 million primarily due to an increase in the debt component of AFUDC related to projects at the Cook Plant.
 
·
Income Tax Expense increased $23 million primarily due to an increase in pretax book income.

 
109
 
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 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, 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 230 for a discussion of accounting pronouncements.

 
110
 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
  
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
  
For the Three and Nine Months Ended September 30, 2013 and 2012
  
(in thousands)
  
(Unaudited)
  
 
  
 
  
Three Months Ended
    
Nine Months Ended
  
 
  
September 30,
    
September 30,
  
 
  
2013
    
2012
    
2013
    
2012
  
REVENUES
  
 
    
 
    
 
    
 
  
Electric Generation, Transmission and Distribution
   $ 537,453     $ 499,078     $ 1,518,357     $ 1,371,070  
Sales to AEP Affiliates
     73,576       71,324       159,888       192,967  
Other Revenues – Affiliated
     27,322       27,034       89,962       86,797  
Other Revenues – Nonaffiliated
     514       768       3,552       4,453  
TOTAL REVENUES
     638,865       598,204       1,771,759       1,655,287  
 
                                
EXPENSES
                                
Fuel and Other Consumables Used for Electric Generation
     140,193       137,960       330,088       347,045  
Purchased Electricity for Resale
     32,976       23,399       111,602       88,797  
Purchased Electricity from AEP Affiliates
     116,511       110,891       317,434       281,032  
Other Operation
     136,702       141,728       414,418       411,218  
Maintenance
     43,448       44,308       139,200       133,817  
Depreciation and Amortization
     45,393       37,734       131,991       109,273  
Taxes Other Than Income Taxes
     21,278       21,698       65,899       62,491  
TOTAL EXPENSES
     536,501       517,718       1,510,632       1,433,673  
 
                                
OPERATING INCOME
     102,364       80,486       261,127       221,614  
 
                                
Other Income (Expense):
                                
Interest Income
     2,360       453       7,077       2,228  
Allowance for Equity Funds Used During Construction
     5,041       1,596       15,568       6,931  
Interest Expense
     (23,932 )     (26,307 )     (72,579 )     (76,733 )
 
                                
INCOME BEFORE INCOME TAX EXPENSE
     85,833       56,228       211,193       154,040  
 
                                
Income Tax Expense
     27,953       16,974       69,102       45,755  
 
                                
NET INCOME
   $ 57,880     $ 39,254     $ 142,091     $ 108,285  
 
                                
The common stock of I&M is wholly-owned by AEP.
                                
 
                                
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
  

 
111
 


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
  
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
  
For the Three and Nine Months Ended September 30, 2013 and 2012
  
(in thousands)
  
(Unaudited)
  
 
  
 
    
 
    
 
    
 
  
 
Three Months Ended
  
Nine Months Ended
  
 
September 30,
  
September 30,
  
 
  
2013
    
2012
    
2013
    
2012
  
Net Income
   $ 57,880     $ 39,254     $ 142,091     $ 108,285  
 
                                
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                                
Cash Flow Hedges, Net of Tax of $132 and $217 for the Three Months Ended
                                
September 30, 2013 and 2012, Respectively, and $1,986 and $2,897 for the
                                
Nine Months Ended September 30, 2013 and 2012, Respectively
     244       (404 )     3,688       (5,381 )
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $94
                                
and $150 for the Three Months Ended September 30, 2013 and 2012,
                                
Respectively, and $283 and $450 for the Nine Months Ended September 30, 2013
                                
and 2012, Respectively
     174       278       525       835  
 
                                
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
     418       (126 )     4,213       (4,546 )
 
                                
TOTAL COMPREHENSIVE INCOME
   $ 58,298     $ 39,128     $ 146,304     $ 103,739  
 
                                
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
  

 
112
 


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
  
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
  
COMMON SHAREHOLDER'S EQUITY
  
For the Nine Months Ended September 30, 2013 and 2012
  
(in thousands)
  
(Unaudited)
  
 
  
 
  
 
    
 
    
 
    
Accumulated
    
 
  
 
  
 
    
 
    
 
    
Other
    
 
  
 
  
Common
    
Paid-in
    
Retained
    
Comprehensive
    
 
  
 
  
Stock
    
Capital
    
Earnings
    
Income (Loss)
    
Total
  
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 )
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  
 
                                        
TOTAL COMMON SHAREHOLDER'S
                                        
EQUITY – DECEMBER 31, 2012
   $ 56,584     $ 980,896     $ 795,178     $ (28,883 )   $ 1,803,775  
 
                                        
Common Stock Dividends
                     (47,500 )             (47,500 )
Net Income
                     142,091               142,091  
Other Comprehensive Income
                             4,213       4,213  
TOTAL COMMON SHAREHOLDER'S
                                        
EQUITY – SEPTEMBER 30, 2013
   $ 56,584     $ 980,896     $ 889,769     $ (24,670 )   $ 1,902,579  
 
                                        
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
  

 
113
 


 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
ASSETS
 
September 30, 2013 and December 31, 2012
 
(in thousands)
 
(Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30,
 
December 31,
 
 
 
2013 
 
2012 
 
CURRENT ASSETS
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 1,798 
 
$
 1,562 
 
Advances to Affiliates
 
 
 322,476 
 
 
 116,977 
 
Accounts Receivable:
 
 
 
 
 
 
 
 
Customers
 
 
 52,482 
 
 
 61,776 
 
 
Affiliated Companies
 
 
 67,744 
 
 
 79,886 
 
 
Accrued Unbilled Revenues
 
 
 16,469 
 
 
 11,218 
 
 
Miscellaneous
 
 
 5,291 
 
 
 12,260 
 
 
Allowance for Uncollectible Accounts
 
 
 (186)
 
 
 (229)
 
 
 
Total Accounts Receivable
 
 
 141,800 
 
 
 164,911 
 
Fuel
 
 
 71,372 
 
 
 53,406 
 
Materials and Supplies
 
 
 187,040 
 
 
 195,147 
 
Risk Management Assets
 
 
 16,150 
 
 
 26,974 
 
Deferred Cook Plant Fire Costs
 
 
 - 
 
 
 80,000 
 
Prepayments and Other Current Assets
 
 
 39,328 
 
 
 83,270 
 
TOTAL CURRENT ASSETS
 
 
 779,964 
 
 
 722,247 
 
 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
 
Generation
 
 
 4,177,462 
 
 
 4,062,733 
 
 
Transmission
 
 
 1,311,364 
 
 
 1,278,236 
 
 
Distribution
 
 
 1,594,559 
 
 
 1,553,358 
 
Other Property, Plant and Equipment (Including Nuclear Fuel and Coal Mining)
 
 
 729,516 
 
 
 725,313 
 
Construction Work in Progress
 
 
 388,835 
 
 
 341,063 
 
Total Property, Plant and Equipment
 
 
 8,201,736 
 
 
 7,960,703 
 
Accumulated Depreciation, Depletion and Amortization
 
 
 3,301,177 
 
 
 3,232,135 
 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
 
 4,900,559 
 
 
 4,728,568 
 
 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
 
Regulatory Assets
 
 
 567,402 
 
 
 540,019 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 1,839,118 
 
 
 1,705,772 
 
Long-term Risk Management Assets
 
 
 13,733 
 
 
 23,569 
 
Deferred Charges and Other Noncurrent Assets
 
 
 87,016 
 
 
 111,364 
 
TOTAL OTHER NONCURRENT ASSETS
 
 
 2,507,269 
 
 
 2,380,724 
 
 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 8,187,792 
 
$
 7,831,539 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
 
 
114
 
 
 
 
 
 
 
 
 
 
 
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
September 30, 2013 and December 31, 2012
 
(dollars in thousands)
 
(Unaudited)
 
 
 
 
 
 
 
September 30,
 
December 31,
 
 
 
 
 
2013 
 
2012 
 
CURRENT LIABILITIES
 
 
 
 
 
 
 
Accounts Payable:
 
 
 
 
 
 
 
 
General
 
$
 120,821 
 
$
 208,701 
 
 
Affiliated Companies
 
 
 64,779 
 
 
 104,631 
 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 
 
 
 
 
 
(September 30, 2013 and December 31, 2012 Amounts Include $137,636 and
 
 
 
 
 
 
 
 
$119,890, Respectively, Related to DCC Fuel)
 
 
 224,859 
 
 
 203,953 
 
Risk Management Liabilities
 
 
 9,268 
 
 
 31,517 
 
Customer Deposits
 
 
 30,702 
 
 
 31,142 
 
Accrued Taxes
 
 
 45,223 
 
 
 67,675 
 
Accrued Interest
 
 
 18,855 
 
 
 26,859 
 
Other Current Liabilities
 
 
 131,823 
 
 
 122,053 
 
TOTAL CURRENT LIABILITIES
 
 
 646,330 
 
 
 796,531 
 
 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 2,046,754 
 
 
 1,853,713 
 
Long-term Risk Management Liabilities
 
 
 8,307 
 
 
 13,898 
 
Deferred Income Taxes
 
 
 1,120,947 
 
 
 1,019,160 
 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 1,042,494 
 
 
 948,292 
 
Asset Retirement Obligations
 
 
 1,234,540 
 
 
 1,192,313 
 
Deferred Credits and Other Noncurrent Liabilities
 
 
 185,841 
 
 
 203,857 
 
TOTAL NONCURRENT LIABILITIES
 
 
 5,638,883 
 
 
 5,231,233 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 6,285,213 
 
 
 6,027,764 
 
 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
 
Commitments and Contingencies (Note 4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
 
 
 
Common Stock – No Par Value:
 
 
 
 
 
 
 
 
Authorized – 2,500,000 Shares
 
 
 
 
 
 
 
 
Outstanding – 1,400,000 Shares
 
 
 56,584 
 
 
 56,584 
 
Paid-in Capital
 
 
 980,896 
 
 
 980,896 
 
Retained Earnings
 
 
 889,769 
 
 
 795,178 
 
Accumulated Other Comprehensive Income (Loss)
 
 
 (24,670)
 
 
 (28,883)
 
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 1,902,579 
 
 
 1,803,775 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
 8,187,792 
 
$
 7,831,539 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

 
115
 


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2013 and 2012
(in thousands)
(Unaudited)
 
 
 
 
 
 
Nine Months Ended September 30,
 
 
2013 
 
2012 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net Income
 
$
 142,091 
 
$
 108,285 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 131,991 
 
 
 109,273 
 
 
Deferred Income Taxes
 
 
 84,067 
 
 
 46,365 
 
 
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net
 
 
 (15,450)
 
 
 2,598 
 
 
Allowance for Equity Funds Used During Construction
 
 
 (15,568)
 
 
 (6,931)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 12,995 
 
 
 9,882 
 
 
Amortization of Nuclear Fuel
 
 
 101,316 
 
 
 100,435 
 
 
Fuel Over/Under-Recovery, Net
 
 
 6,459 
 
 
 2,867 
 
 
Change in Other Noncurrent Assets
 
 
 (718)
 
 
 14,214 
 
 
Change in Other Noncurrent Liabilities
 
 
 25,249 
 
 
 46,263 
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 23,111 
 
 
 25,415 
 
 
 
Fuel, Materials and Supplies
 
 
 (9,859)
 
 
 7,315 
 
 
 
Accounts Payable
 
 
 (35,517)
 
 
 (75,799)
 
 
 
Accrued Taxes, Net
 
 
 (8,987)
 
 
 7,398 
 
 
 
Other Current Assets
 
 
 18,948 
 
 
 (3,368)
 
 
 
Other Current Liabilities
 
 
 (4,130)
 
 
 39,541 
Net Cash Flows from Operating Activities
 
 
 455,998 
 
 
 433,753 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
Construction Expenditures
 
 
 (360,668)
 
 
 (212,006)
Change in Advances to Affiliates, Net
 
 
 (205,499)
 
 
 (189,054)
Purchases of Investment Securities
 
 
 (675,727)
 
 
 (744,131)
Sales of Investment Securities
 
 
 635,256 
 
 
 698,567 
Acquisitions of Nuclear Fuel
 
 
 (109,598)
 
 
 (12,545)
Insurance Proceeds Related to Cook Plant Fire
 
 
 72,000 
 
 
 - 
Other Investing Activities
 
 
 27,888 
 
 
 29,714 
Net Cash Flows Used for Investing Activities
 
 
 (616,348)
 
 
 (429,455)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
 
 348,892 
 
 
 128,228 
Retirement of Long-term Debt – Nonaffiliated
 
 
 (137,544)
 
 
 (78,062)
Principal Payments for Capital Lease Obligations
 
 
 (4,112)
 
 
 (4,929)
Dividends Paid on Common Stock
 
 
 (47,500)
 
 
 (50,000)
Other Financing Activities
 
 
 850 
 
 
 212 
Net Cash Flows from (Used for) Financing Activities
 
 
 160,586 
 
 
 (4,551)
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 236 
 
 
 (253)
Cash and Cash Equivalents at Beginning of Period
 
 
 1,562 
 
 
 1,020 
Cash and Cash Equivalents at End of Period
 
$
 1,798 
 
$
 767 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 76,468 
 
$
 79,158 
Net Cash Paid (Received) for Income Taxes
 
 
 (35,307)
 
 
 (29,089)
Noncash Acquisitions Under Capital Leases
 
 
 2,858 
 
 
 4,993 
Construction Expenditures Included in Current Liabilities as of September 30,
 
 
 54,082 
 
 
 43,334 
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,
 
 
 279 
 
 
 42,957 
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage
 
 
 19 
 
 
 28,057 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

 
116
 

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.

 
Page
 
Number
   
Significant Accounting Matters
   162
Comprehensive Income
   162
Rate Matters
   175
Commitments, Guarantees and Contingencies
   186
Benefit Plans
   191
Business Segments
   194
Derivatives and Hedging
   195
Fair Value Measurements
   208
Income Taxes
   220
Financing Activities
   221
Variable Interest Entities
   225
Sustainable Cost Reductions
   229

 
117
 
 
OHIO POWER COMPANY AND SUBSIDIARIES

 
118
 
OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Ohio Customer Choice

In OPCo’s service territory, various CRES providers are targeting retail customers by offering alternative generation service.  The reduction in gross margin as a result of customer switching in Ohio 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.

Ormet

Ormet has a contract to purchase power from OPCo through 2018.  In October 2013, Ormet announced that it is unable to emerge from bankruptcy and that it has shut down its operations effective immediately.  The loss of Ormet's load will not have a material impact on future gross margin.  Power previously sold to Ormet will be available to be sold into wholesale markets.

Regulatory Activity

Ohio Electric Security Plan Filing

2009 – 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover OPCo’s deferred fuel costs in rates beginning September 2012.  As of September 30, 2013, OPCo’s net deferred fuel balance was $467 million, excluding unrecognized equity carrying costs.  Decisions from the Supreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance.

June 2012 – May 2015 Ohio ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015, which was generally upheld in rehearing orders in January and March 2013.

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 up to $188.88/MW day.  The RPM price is approximately $33/MW day through May 2014.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.  As of September 30, 2013, OPCo’s incurred deferred capacity costs balance was $228 million, including debt carrying costs.

As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR 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 April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR.

In June 2013, intervenors in the competitive bid process (CBP) docket filed recommendations that include prospective rate reductions for capacity and non-energy FAC issues.  OPCo maintains that the August 2012 ESP order fixed OPCo’s non-energy generation rates through December 31, 2014 and ordered the application of a $188.88/MW day price for capacity for non-shopping customers effective January 1, 2015.  However, intervenors maintained that OPCo’s non-energy generation rates should be reduced prior to January 1, 2015 to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned (10% prior to June 2014 and 60% for the period June 1, 2014 through December 31, 2014).  Depending upon actual customer switching levels and the timing of the auctions, OPCo estimates that these capacity issues could reduce OPCo’s
 
 
119
 
projected future revenues by up to approximately $155 million for the period January 2014 through May 2015, if adopted by the PUCO.  An additional proposal to prospectively offset deferred capacity costs based upon the results of the energy-only auctions was not quantified and OPCo maintains that proposal should not be adopted in light of prior PUCO orders.  Hearings related to the CBP were held at the PUCO in June and July 2013.  A decision from the PUCO is pending. 

If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its deferred capacity costs, it could reduce future net income and cash flows and impact financial condition.  See “Ohio Electric Security Plan Filing” section of Note 3.

Corporate Separation, Plant Transfers and Termination of Interconnection Agreement

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets at net book value (NBV) to AEPGenCo.  AEPGenCo will also assume the associated generation liabilities.  In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.  A decision from the Supreme Court of Ohio is pending.  In October 2013, OPCo filed an application with the PUCO to amend the corporate separation plan by permitting OPCo to retain certain rights to purchase power from OVEC.

Also in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations.  The filings requested approval to transfer at NBV approximately 9,200 MW of OPCo-owned generation assets to AEPGenCo.  The AEP East Companies also requested FERC approval to transfer at NBV OPCo’s current two-thirds ownership in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests.  In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AEPGenCo and the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo, to be effective using the requested date of December 31, 2013.  In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo.  OPCo has contested the petition for rehearing, which remains pending before the FERC.  In July 2013, the Virginia SCC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo, but denied the proposed transfer of OPCo’s one-half interest in the Mitchell Plant to APCo.  In September 2013, a WVPSC staff brief advocated for the approval of the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo, and the denial of the proposed transfer of OPCo’s one-half interest in the Mitchell Plant to APCo.  In October 2013, the KPSC approved a modified settlement agreement that included the transfer of the one-half interest in the Mitchell Plant to KPCo at net book value.  See the “Plant Transfers” sections of APCo Rate Matters in Note 3.
  
In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by recent orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation.  See the “Plant Transfers” section of APCo Rate Matters in Note 3 for a discussion of the Virginia SCC order.

Additionally, the AEP East Companies requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  In March 2013, a revised PCA was filed at the FERC that included certain clarifying wording changes agreed upon by intervenors.  A decision is pending from the FERC.  See the “Corporate Separation and Termination of Interconnection Agreement” section of Note 3.

Significantly Excessive Earnings Test

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  In October 2013, the PUCO issued an order on the 2010 SEET filing.  As a result, the PUCO ordered a $7 million refund of pretax earnings to customers.  OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis.  Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in 2012 for OPCo.  Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo.  Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition.  See “Ohio Electric Security Plan Filing” section of Note 3.

 
120
 
Securitization of Regulatory Assets

In March 2013, the PUCO approved OPCo’s request to securitize the Deferred Asset Recovery Rider (DARR) balance.  The DARR was originally scheduled to be recovered through 2018 by a non-bypassable rider.  In August 2013, OPCo issued $267 million of Securitization Bonds to securitize the DARR balance.  As a result of the securitization, recovery through the DARR has ceased and has been replaced by the Deferred Asset Phase-in Rider which will recover the securitized transition assets over a period not to exceed eight years.

Muskingum River Plant, Unit 5 Impairment

Muskingum River Plant, Unit 5 (MR5) had options under a consent decree to cease burning coal and retire in 2015 or cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017.  In the second quarter of 2013, management re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project which would have extended the useful life of MR5 is remote.  As a result, in the second quarter of 2013, OPCo completed an impairment analysis and recorded a $154 million ($99 million, net of tax) pretax impairment charge for OPCo’s net book value of MR5.  Management expects to retire the plant in 2015.  See “Muskingum River Plant, Unit 5” section of Note 5.

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 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 161.  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 230 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,
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 3,742 
 
 
 4,198 
 
 
 11,006 
 
 
 11,079 
 
Commercial
 
 3,820 
 
 
 3,907 
 
 
 10,712 
 
 
 10,725 
 
Industrial
 
 4,012 
 
 
 4,463 
 
 
 12,297 
 
 
 13,982 
 
Miscellaneous
 
 29 
 
 
 27 
 
 
 91 
 
 
 85 
Total Retail (a)
 
 11,603 
 
 
 12,595 
 
 
 34,106 
 
 
 35,871 
 
 
 
 
 
 
 
 
 
 
 
 
Wholesale
 
 4,222 
 
 
 4,173 
 
 
 9,683 
 
 
 9,477 
 
 
 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 15,825 
 
 
 16,768 
 
 
 43,789 
 
 
 45,348 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Represents energy delivered to distribution customers.

 
121
 
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,
 
 
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
(in degree days)
 
Actual - Heating (a)
 
 1 
 
 
 9 
 
 
 2,165 
 
 
 1,553 
 
Normal - Heating (b)
 
 8 
 
 
 8 
 
 
 2,083 
 
 
 2,121 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 646 
 
 
 807 
 
 
 991 
 
 
 1,235 
 
Normal - Cooling (b)
 
 660 
 
 
 662 
 
 
 940 
 
 
 934 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

 
122
 
Third Quarter of 2013 Compared to Third Quarter of 2012
   
Reconciliation of Third Quarter of 2012 to Third Quarter of 2013
  
Net Income
  
(in millions)
  
 
  
 
  
Third Quarter of 2012
   $ 152  
 
        
Changes in Gross Margin:
        
Retail Margins
     (22 )
Off-system Sales
     (18 )
Transmission Revenues
     12  
Other Revenues
     (5 )
Total Change in Gross Margin
     (33 )
 
        
Changes in Expenses and Other:
        
Other Operation and Maintenance
     31  
Depreciation and Amortization
     35  
Carrying Costs Income
     (4 )
Interest Expense
     9  
Total Change in Expenses and Other
     71  
 
        
Income Tax Expense
     (11 )
 
        
Third Quarter of 2013
   $ 179  

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 $22 million primarily due to the following:
   
·
A $70 million decrease attributable to customers switching to alternative CRES providers.  This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
   
·
A $23 million decrease in weather-related usage primarily due to a 20% decrease in cooling degree days.
   
·
A $9 million decrease due to a reduction in weather-normalized residential usage.
   
These decreases were partially offset by:
   
·
A $62 million increase in revenues associated with the Universal Service Fund (USF) surcharge, Retail Stability Rider, Deferred Asset Phase-In Rider and Distribution Investment Recovery Rider.  Of these increases, $33 million relate to riders/trackers which have corresponding increases in other expense items below.
   
·
A $16 million increase due to the deferral of consumables and purchased power as a result of the PUCO’s July 2012 approval of the capacity deferral mechanism.
 
·
Margins from Off-system Sales decreased $18 million primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower physical sales margins, reduced trading and marketing margins and true-up of prior period PJM expenses. The decrease in CRES capacity revenues is partially offset in other expense items below.
 
·
 
Transmission Revenues increased $12 million primarily due to increased transmission revenues from customers who have switched to alternative CRES providers and rate increases for customers in the PJM region.  The increase in transmission revenues related to CRES providers offsets lost revenues included in Retail Margins above.
 
·
Other Revenues decreased $5 million due to:
   
·
A $10 million decrease in revenues related to the Cook Coal Terminal which was transferred to AEGCo in August 2013. This decrease in Other Revenues has a corresponding decrease in Other Operation and Maintenance expense below.
   
This decrease was partially offset by:
   
·
A $5 million increase associated with billings to affiliated companies.

 
123
 
Expenses and Other and Income Tax Expense changed between years as follows:

 
·
Other Operation and Maintenance expenses decreased $31 million primarily due to the following:
   
·
A $12 million decrease in employee-related expenses.
   
·
A $10 million decrease in expenses related to the Cook Coal Terminal which was transferred to AEGCo in August 2013. This decrease in Other Operation and Maintenance has a corresponding decrease in Other Revenues above.
   
·
An $8 million decrease due to the deferral of capacity-related costs as a result of the PUCO's July 2012 approval of the capacity deferral mechanism.
   
·
A $6 million decrease related to the third quarter 2012 recording of an obligation to contribute to Ohio Growth Fund as approved by the PUCO in August 2012.
   
·
A $6 million decrease in recoverable PJM expenses.
   
·
A $4 million decrease due to updated gridSMART rider allocation ratios between capital carrying charges and operations expense beginning in January 2013. This decrease was partially offset by a corresponding increase in Depreciation and Amortization.
   
These decreases were partially offset by:
   
·
A $19 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase was offset by a corresponding increase in Retail Margins above.
 
·
Depreciation and Amortization expenses decreased $35 million primarily due to the following:
   
·
A $34 million decrease as a result of depreciation ceasing on certain generating plants that were impaired in November 2012 and June 2013.
   
·
A $9 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of the capacity deferral mechanism.
 
·
Carrying Costs Income decreased $4 million due to 2012 Ohio FAC carrying charges. No carrying charges were recorded in 2013 due to the implementation of the Phase-in Recovery Rider in September 2012.
 
·
Interest Expense decreased $9 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
 
·
Income Tax Expense increased $11 million primarily due to an increase in pretax book income.

 
124
 
Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012
 
  
 
  
Reconciliation of Nine Months Ended September 30, 2012 to Nine Months Ended September 30, 2013
  
Net Income
  
(in millions)
  
 
  
 
  
Nine Months Ended September 30, 2012
   $ 404  
 
        
Changes in Gross Margin:
        
Retail Margins
     (25 )
Off-system Sales
     (92 )
Transmission Revenues
     28  
Other Revenues
     (5 )
Total Change in Gross Margin
     (94 )
 
        
Changes in Expenses and Other:
        
Other Operation and Maintenance
     9  
Asset Impairments and Other Related Charges
     (154 )
Depreciation and Amortization
     112  
Carrying Costs Income
     (4 )
Interest Expense
     18  
Total Change in Expenses and Other
     (19 )
 
        
Income Tax Expense
     39  
 
        
Nine Months Ended September 30, 2013
   $ 330  

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 $25 million primarily due to the following:
   
·
A $223 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 $35 million decrease 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 $17 million decrease due to lower sales to Buckeye Power, Inc. to provide backup energy under the Cardinal Station Agreement.
   
·
A $14 million decrease due to a reduction in industrial usage.
   
·
A $9 million decrease in weather-related usage primarily due to a 20% decrease in cooling degree days.
   
These decreases were partially offset by:
   
·
A $208 million increase in revenues associated with the USF surcharge, Retail Stability Rider, Deferred Asset Recovery Rider and Distribution Investment Recovery Rider.  Of these increases, $113 million relate to riders/trackers which have corresponding increases in other expense items below.
   
·
A $64 million increase due to the deferral of consumables and purchased power as a result of the PUCO’s July 2012 approval of the capacity deferral mechanism.
 
·
Margins from Off-system Sales decreased $92 million primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity revenues, reduced trading and marketing margins and true-up of prior period PJM expenses. The decrease in CRES capacity revenues is partially offset in other expense items below.
 
·
Transmission Revenues increased $28 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.
 
 
125
 
 
·
Other Revenues decreased $5 million due to:
   
·
A $10 million decrease in revenues related to the Cook Coal Terminal which was transferred to AEGCo in August 2013. This decrease in Other Revenues has a corresponding decrease in Other Operation and Maintenance expense below.
   
This decrease was partially offset by:
     ·  A $5 million increase associated with billings to affiliated companies.

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

 
·
Other Operation and Maintenance expenses decreased $9 million primarily due to the following:
   
·
A $28 million decrease due to the deferral of capacity-related costs as a result of the PUCO's July 2012 approval of the capacity deferral mechanism.
   
·
A $16 million decrease in recoverable PJM expenses.
   
·
An $11 million decrease due to updated gridSMART rider allocation ratios between capital carrying charges and operations expense beginning in January 2013. This decrease was partially offset by a corresponding increase in Depreciation and Amortization.
   
·
A $10 million decrease in expenses related to the Cook Coal Terminal which was transferred to AEGCo in August 2013. This decrease in Other Operation and Maintenance has a corresponding decrease in Other Revenues above.
   
·
An $8 million decrease primarily due to the 2012 reversal of storm damage deferrals as a result of the PUCO’s February 2012 rejection of the Ohio modified stipulation.
   
·
An $8 million decrease in advertising expenses.
   
·
A $7 million decrease in plant maintenance expenses at various plants.
   
·
A $5 million decrease in employee-related expenses.
   
·
A $3 million decrease in customer records and collection expenses.
   
These decreases were partially offset by:
   
·
A $64 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase was offset by a corresponding increase in Retail Margins above.
   
·
A $30 million net increase 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.
 
·
Asset Impairments and Other Related Charges increased $154 million due to the second quarter 2013 impairment of Muskingum River Plant, Unit 5.
 
·
Depreciation and Amortization expenses decreased $112 million primarily due to the following:
   
·
A $92 million decrease as a result of depreciation ceasing on certain generating plants that were impaired in November 2012 and June 2013.
   
·
A $44 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO’s July 2012 approval of the capacity deferral mechanism.
   
These decreases were partially offset by:
   
·
A $9 million increase due to an increase in depreciable base.
 
·
Carrying Costs Income decreased $4 million due to the following:
   
·
A $15 million decrease due to 2012 Ohio FAC carrying charges.  No carrying charges were recorded in 2013 due to the implementation of the Phase-in Recovery Rider in September 2012.
   
This decrease was offset by:
   
·
A $5 million increase in carrying charges on the deferred capacity-related costs as a result of the PUCO’s July 2012 approval of the capacity deferral mechanism.
   
·
A $5 million increase due to the 2012 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.
 
·
Interest Expense decreased $18 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
 
·
Income Tax Expense decreased $39 million primarily due to a decrease in pretax book income.

 
126
 
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 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, 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 230 for a discussion of accounting pronouncements.

 
127
 

OHIO POWER COMPANY AND SUBSIDIARIES
  
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
  
For the Three and Nine Months Ended September 30, 2013 and 2012
  
(in thousands)
  
(Unaudited)
  
 
  
 
  
Three Months Ended
    
Nine Months Ended
  
 
  
September 30,
    
September 30,
  
 
  
2013
    
2012
    
2013
    
2012
  
REVENUES
  
 
    
 
    
 
    
 
  
Electric Generation, Transmission and Distribution
   $ 959,816     $ 1,114,339     $ 2,710,990     $ 3,084,657  
Sales to AEP Affiliates
     313,818       229,879       873,850       584,197  
Other Revenues – Affiliated
     2,715       10,207       18,138       27,297  
Other Revenues – Nonaffiliated
     2,827       5,391       12,982       14,638  
TOTAL REVENUES
     1,279,176       1,359,816       3,615,960       3,710,789  
 
                                
EXPENSES
                                
Fuel and Other Consumables Used for Electric Generation
     396,437       426,989       1,158,389       1,095,276  
Purchased Electricity for Resale
     34,568       46,146       114,911       156,384  
Purchased Electricity from AEP Affiliates
     103,869       109,453       257,540       279,954  
Other Operation
     159,965       189,566       481,417       481,994  
Maintenance
     71,670       73,024       218,962       227,643  
Asset Impairments and Other Related Charges
     -       -       154,304       -  
Depreciation and Amortization
     94,802       130,026       289,472       401,465  
Taxes Other Than Income Taxes
     105,070       105,503       310,285       309,341  
TOTAL EXPENSES
     966,381       1,080,707       2,985,280       2,952,057  
 
                                
OPERATING INCOME
     312,795       279,109       630,680       758,732  
 
                                
Other Income (Expense):
                                
Interest Income
     476       425       3,165       1,868  
Carrying Costs Income
     2,813       7,132       9,833       14,401  
Allowance for Equity Funds Used During Construction
     1,028       998       2,853       3,036  
Interest Expense
     (45,070 )     (53,576 )     (142,487 )     (160,984 )
 
                                
INCOME BEFORE INCOME TAX EXPENSE
     272,042       234,088       504,044       617,053  
 
                                
Income Tax Expense
     93,141       82,578       174,313       213,290  
 
                                
NET INCOME
   $ 178,901     $ 151,510     $ 329,731     $ 403,763  
 
                                
The common stock of OPCo is wholly-owned by AEP.
                                
 
                                
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
  

 
128
 


OHIO POWER COMPANY AND SUBSIDIARIES
  
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
  
For the Three and Nine Months Ended September 30, 2013 and 2012
  
(in thousands)
  
(Unaudited)
  
 
  
 
    
 
    
 
    
 
  
 
      Three Months Ended       Nine Months Ended  
 
     September 30,    
September 30,
  
 
  
2013
    
2012
    
2013
    
2012
  
Net Income
   $ 178,901     $ 151,510     $ 329,731     $ 403,763  
 
                                
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                                
Cash Flow Hedges, Net of Tax of $363 and $956 for the Three Months Ended
                                
September 30, 2013 and 2012, Respectively, and $83 and $111 for the Nine
                                
Months Ended September 30, 2013 and 2012, Respectively
     (675 )     1,776       (154 )     205  
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,607
                                
and $1,745 for the Three Months Ended September 30, 2013 and 2012,
                                
Respectively, and $5,128 and $5,234 for the Nine Months Ended
                                
September 30, 2013 and 2012, Respectively
     2,985       3,240       9,524       9,721  
 
                                
TOTAL OTHER COMPREHENSIVE INCOME
     2,310       5,016       9,370       9,926  
 
                                
TOTAL COMPREHENSIVE INCOME
   $ 181,211     $ 156,526     $ 339,101     $ 413,689  
 
                                
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
  

 
129
 


OHIO POWER COMPANY AND SUBSIDIARIES
  
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
  
COMMON SHAREHOLDER'S EQUITY
  
For the Nine Months Ended September 30, 2013 and 2012
  
(in thousands)
  
(Unaudited)
  
 
 
    
 
  
 
  
 
    
 
    
 
    
Accumulated
    
 
  
 
  
 
    
 
    
 
    
Other
    
 
  
 
  
Common
    
Paid-in
    
Retained
    
Comprehensive
    
 
  
 
  
Stock
    
Capital
    
Earnings
    
Income (Loss)
    
Total
  
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 )
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  
 
                                        
TOTAL COMMON SHAREHOLDER'S
                                        
EQUITY – DECEMBER 31, 2012
   $ 321,201     $ 1,744,099     $ 2,626,134     $ (165,725 )   $ 4,525,709  
 
                                        
Distribution of Cook Coal Terminal to Parent
                     (22,303 )     19,652       (2,651 )
Common Stock Dividends
                     (275,000 )             (275,000 )
Net Income
                     329,731               329,731  
Other Comprehensive Income
                             9,370       9,370  
TOTAL COMMON SHAREHOLDER'S
                                        
EQUITY –  SEPTEMBER 30, 2013
   $ 321,201     $ 1,744,099     $ 2,658,562     $ (136,703 )   $ 4,587,159  
 
                                        
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
  

 
130
 


 
OHIO POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
ASSETS
 
September 30, 2013 and December 31, 2012
 
(in thousands)
 
(Unaudited)
 
 
 
 
 
 
 
September 30,
 
December 31,
 
 
 
2013 
 
2012 
 
CURRENT ASSETS
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 4,341 
 
$
 3,640 
 
Advances to Affiliates
 
 
 10,126 
 
 
 116,422 
 
Accounts Receivable:
 
 
 
 
 
 
 
 
Customers
 
 
 83,382 
 
 
 135,954 
 
 
Affiliated Companies
 
 
 147,471 
 
 
 176,590 
 
 
Accrued Unbilled Revenues
 
 
 38,753 
 
 
 57,887 
 
 
Miscellaneous
 
 
 6,683 
 
 
 9,327 
 
 
Allowance for Uncollectible Accounts
 
 
 (26,966)
 
 
 (129)
 
 
 
Total Accounts Receivable
 
 
 249,323 
 
 
 379,629 
 
Fuel
 
 
 251,888 
 
 
 328,840 
 
Materials and Supplies
 
 
 173,397 
 
 
 186,269 
 
Risk Management Assets
 
 
 34,178 
 
 
 44,313 
 
Accrued Tax Benefits
 
 
 947 
 
 
 17,785 
 
Prepayments and Other Current Assets
 
 
 50,199 
 
 
 26,807 
 
TOTAL CURRENT ASSETS
 
 
 774,399 
 
 
 1,103,705 
 
 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
 
Generation
 
 
 8,392,967 
 
 
 8,673,296 
 
 
Transmission
 
 
 2,034,958 
 
 
 2,013,737 
 
 
Distribution
 
 
 3,815,303 
 
 
 3,722,745 
 
Other Property, Plant and Equipment
 
 
 566,007 
 
 
 571,154 
 
Construction Work in Progress
 
 
 440,199 
 
 
 354,497 
 
Total Property, Plant and Equipment
 
 
 15,249,434 
 
 
 15,335,429 
 
Accumulated Depreciation and Amortization
 
 
 5,220,979 
 
 
 5,242,805 
 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
 
 10,028,455 
 
 
 10,092,624 
 
 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
 
Regulatory Assets
 
 
 1,455,176 
 
 
 1,420,966 
 
Securitized Transition Assets
 
 
 136,566 
 
 
 - 
 
Long-term Risk Management Assets
 
 
 28,594 
 
 
 48,288 
 
Deferred Charges and Other Noncurrent Assets
 
 
 133,024 
 
 
 320,026 
 
TOTAL OTHER NONCURRENT ASSETS
 
 
 1,753,360 
 
 
 1,789,280 
 
 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 12,556,214 
 
$
 12,985,609 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
 
 
131
 
 
 
OHIO POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
September 30, 2013 and December 31, 2012
 
(Unaudited)
 
 
 
 
 
 
 
September 30,
 
December 31,
 
 
 
2013 
 
2012 
 
 
 
 
(in thousands)
 
CURRENT LIABILITIES
 
 
 
 
 
 
 
Advances from Affiliates
 
$
 1,063 
 
$
 - 
 
Accounts Payable:
 
 
 
 
 
 
 
 
General
 
 
 249,663 
 
 
 276,220 
 
 
Affiliated Companies
 
 
 99,322 
 
 
 153,222 
 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 553,516 
 
 
 856,000 
 
Risk Management Liabilities
 
 
 16,431 
 
 
 24,155 
 
Accrued Taxes
 
 
 261,496 
 
 
 467,309 
 
Accrued Interest
 
 
 54,603 
 
 
 63,560 
 
Other Current Liabilities
 
 
 201,018 
 
 
 263,638 
 
TOTAL CURRENT LIABILITIES
 
 
 1,437,112 
 
 
 2,104,104 
 
 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 2,945,058 
 
 
 2,804,440 
 
Long-term Debt – Affiliated
 
 
 200,000 
 
 
 200,000 
 
Long-term Risk Management Liabilities
 
 
 16,577 
 
 
 25,965 
 
Deferred Income Taxes
 
 
 2,489,349 
 
 
 2,345,850 
 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 444,216 
 
 
 451,071 
 
Deferred Credits and Other Noncurrent Liabilities
 
 
 436,743 
 
 
 528,470 
 
TOTAL NONCURRENT LIABILITIES
 
 
 6,531,943 
 
 
 6,355,796 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 7,969,055 
 
 
 8,459,900 
 
 
 
 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
 
Commitments and Contingencies (Note 4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
 
 
 
Common Stock – No Par Value:
 
 
 
 
 
 
 
 
Authorized – 40,000,000 Shares
 
 
 
 
 
 
 
 
Outstanding – 27,952,473 Shares
 
 
 321,201 
 
 
 321,201 
 
Paid-in Capital
 
 
 1,744,099 
 
 
 1,744,099 
 
Retained Earnings
 
 
 2,658,562 
 
 
 2,626,134 
 
Accumulated Other Comprehensive Income (Loss)
 
 
 (136,703)
 
 
 (165,725)
 
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 4,587,159 
 
 
 4,525,709 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
 12,556,214 
 
$
 12,985,609 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

 
132
 


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2013 and 2012
(in thousands)
(Unaudited)
 
 
 
 
 
 
Nine Months Ended September 30,
 
 
2013 
 
2012 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net Income
 
$
 329,731 
 
$
 403,763 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 289,472 
 
 
 401,465 
 
 
Deferred Income Taxes
 
 
 111,850 
 
 
 126,009 
 
 
Asset Impairments and Other Related Charges
 
 
 154,304 
 
 
 - 
 
 
Carrying Costs Income
 
 
 (9,833)
 
 
 (14,401)
 
 
Allowance for Equity Funds Used During Construction
 
 
 (2,853)
 
 
 (3,036)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 14,037 
 
 
 12,420 
 
 
Property Taxes
 
 
 166,607 
 
 
 164,496 
 
 
Fuel Over/Under-Recovery, Net
 
 
 21,271 
 
 
 4,766 
 
 
Deferral of Ohio Capacity Costs, Net
 
 
 (156,952)
 
 
 (21,541)
 
 
Change in Other Noncurrent Assets
 
 
 (29,012)
 
 
 (55,769)
 
 
Change in Other Noncurrent Liabilities
 
 
 (11,664)
 
 
 (11,019)
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 123,893 
 
 
 29,255 
 
 
 
Fuel, Materials and Supplies
 
 
 79,028 
 
 
 (46,712)
 
 
 
Accounts Payable
 
 
 (67,487)
 
 
 (135,419)
 
 
 
Accrued Taxes, Net
 
 
 (187,677)
 
 
 (161,613)
 
 
 
Other Current Assets
 
 
 3,246 
 
 
 2,599 
 
 
 
Other Current Liabilities
 
 
 (39,251)
 
 
 (3,639)
Net Cash Flows from Operating Activities
 
 
 788,710 
 
 
 691,624 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
Construction Expenditures
 
 
 (445,189)
 
 
 (374,417)
Change in Advances to Affiliates, Net
 
 
 101,616 
 
 
 94,852 
Proceeds from Sales of Assets
 
 
 13,059 
 
 
 6,226 
Other Investing Activities
 
 
 (8,586)
 
 
 8,526 
Net Cash Flows Used for Investing Activities
 
 
 (339,100)
 
 
 (264,813)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
 
 977,002 
 
 
 - 
Issuance of Long-term Debt – Affiliated
 
 
 200,000 
 
 
 - 
Change in Advances from Affiliates, Net
 
 
 1,063 
 
 
 - 
Retirement of Long-term Debt – Nonaffiliated
 
 
 (1,146,000)
 
 
 (194,500)
Retirement of Long-term Debt – Affiliated
 
 
 (200,000)
 
 
 - 
Principal Payments for Capital Lease Obligations
 
 
 (7,920)
 
 
 (7,678)
Dividends Paid on Common Stock
 
 
 (275,000)
 
 
 (225,000)
Other Financing Activities
 
 
 1,946 
 
 
 202 
Net Cash Flows Used for Financing Activities
 
 
 (448,909)
 
 
 (426,976)
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 701 
 
 
 (165)
Cash and Cash Equivalents at Beginning of Period
 
 
 3,640 
 
 
 2,095 
Cash and Cash Equivalents at End of Period
 
$
 4,341 
 
$
 1,930 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 145,817 
 
$
 157,944 
Net Cash Paid for Income Taxes
 
 
 38,446 
 
 
 33,400 
Noncash Acquisitions Under Capital Leases
 
 
 5,756 
 
 
 5,658 
Government Grants Included in Accounts Receivable as of September 30,
 
 
 377 
 
 
 585 
Construction Expenditures Included in Current Liabilities as of September 30,
 
 
 68,481 
 
 
 56,357 
Noncash Distribution of Cook Coal Terminal to Parent
 
 
 (22,303)
 
 
 - 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

 
133
 

OHIO POWER COMPANY AND SUBSIDIARIES
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.

 
Page
 
Number
   
Significant Accounting Matters
   162
Comprehensive Income
   162
Rate Matters
   175
Commitments, Guarantees and Contingencies
   186
Disposition and Impairments
   190
Benefit Plans
   191
Business Segments
   194
Derivatives and Hedging
   195
Fair Value Measurements
   208
Income Taxes
   220
Financing Activities
   221
Variable Interest Entities
   225
Sustainable Cost Reductions
   229

 
134
 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA

 
135
 

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

EXECUTIVE OVERVIEW

Regulatory Activity

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES), Unit 4 in 2016 and additional environmental controls on NES, Unit 3 to continue operations through 2026.  As of September 30, 2013, the net book values of NES, Units 3 and 4 were $182 million and $101 million, respectively, before cost of removal, including materials and supplies inventory and CWIP.  In August 2013, the OCC dismissed PSO’s environmental compliance plan case without prejudice but will permit PSO to seek recovery in a future proceeding.  PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan.  If PSO is ultimately not permitted to fully recover its net book value of NES, Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition.

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 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 161.  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 230 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,
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 2,100 
 
 
 2,332 
 
 
 4,906 
 
 
 5,211 
 
Commercial
 
 1,475 
 
 
 1,518 
 
 
 3,829 
 
 
 3,992 
 
Industrial
 
 1,344 
 
 
 1,346 
 
 
 3,829 
 
 
 3,837 
 
Miscellaneous
 
 353 
 
 
 383 
 
 
 951 
 
 
 1,025 
Total Retail (a)
 
 5,272 
 
 
 5,579 
 
 
 13,515 
 
 
 14,065 
 
 
 
 
 
 
 
 
 
 
 
 
Wholesale
 
 330 
 
 
 334 
 
 
 852 
 
 
 1,273 
 
 
 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 5,602 
 
 
 5,913 
 
 
 14,367 
 
 
 15,338 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Represents energy delivered to distribution customers.

 
136
 
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,
 
 
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
(in degree days)
 
Actual - Heating (a)
 
 - 
 
 
 - 
 
 
 1,208 
 
 
 676 
 
Normal - Heating (b)
 
 2 
 
 
 2 
 
 
 1,084 
 
 
 1,109 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 1,357 
 
 
 1,622 
 
 
 2,006 
 
 
 2,557 
 
Normal - Cooling (b)
 
 1,395 
 
 
 1,398 
 
 
 2,059 
 
 
 2,046 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

 
137
 
Third Quarter of 2013 Compared to Third Quarter of 2012
 
  
 
  
Reconciliation of Third Quarter of 2012 to Third Quarter of 2013
  
Net Income
  
(in millions)
  
 
  
 
  
Third Quarter of 2012
   $ 58  
 
        
Changes in Gross Margin:
        
Retail Margins (a)
     (14 )
Transmission Revenues
     2  
Other Revenues
     3  
Total Change in Gross Margin
     (9 )
 
        
Changes in Expenses and Other:
        
Other Operation and Maintenance
     (1 )
Total Change in Expenses and Other
     (1 )
 
        
Income Tax Expense
     3  
 
        
Third Quarter of 2013
   $ 51  
 
        
(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 $10 million decrease in weather-related usage primarily due to a 16% decrease in cooling degree days.
   
·
A $3 million decrease primarily due to revenue decreases from rate riders.  This decrease in retail margins has corresponding decreases to riders/trackers recognized in other expense items below.
 
·
Other Revenues increased $3 million primarily due to the sale of fuel inventory.

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

 
·
Other Operation and Maintenance expenses increased $1 million primarily due to the following:
   
·
A $4 million increase in transmission expenses primarily due to increased SPP transmission services.
   
·
A $3 million increase in generation plant maintenance expenses.
   
These increases were partially offset by:
   
·
A $3 million decrease in administrative and general expenses.
   
·
A $2 million decrease in distribution expenses primarily due to decreased storm-related expenses.
 
·
Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income.

 
138
 
Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012
 
 
 
 
 
Reconciliation of Nine Months Ended September 30, 2012 to Nine Months Ended September 30, 2013
Net Income
(in millions)
 
 
 
 
 
Nine Months Ended September 30, 2012
 
$
 106 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
Retail Margins (a)
 
 
 (20)
 
Transmission Revenues
 
 
 5 
 
Other Revenues
 
 
 3 
 
Total Change in Gross Margin
 
 
 (12)
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
Other Operation and Maintenance
 
 
 (7)
 
Depreciation and Amortization
 
 
 (1)
 
Taxes Other Than Income Taxes
 
 
 (1)
 
Interest Expense
 
 
 2 
 
Total Change in Expenses and Other
 
 
 (7)
 
 
 
 
 
 
Income Tax Expense
 
 
 6 
 
 
 
 
 
 
Nine Months Ended September 30, 2013
 
$
 93 
 
 
 
 
 
 
(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 $20 million primarily due to the following:
   
·
A $14 million net decrease in weather-related usage primarily due to a 22% decrease in cooling degree days, partially offset by an increase in heating degree days.
   
·
A $7 million decrease primarily due to lower weather-normalized retail sales.
   
These decreases were partially offset by:
   
·
A $3 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.
 
·
Transmission Revenues increased $5 million primarily due to rate increases for customers in the SPP region.
 
·
Other Revenues increased $3 million primarily due to the sale of fuel inventory.

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

 
·
Other Operation and Maintenance expenses increased $7 million primarily due to the following:
   
·
A $13 million increase in transmission expenses primarily due to increased SPP transmission services.
   
This increase was partially offset by:
   
·
A $4 million decrease in administrative and general expenses.
 
·
Income Tax Expense decreased $6 million primarily due to a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, 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 230 for a discussion of accounting pronouncements.

 
139
 

PUBLIC SERVICE COMPANY OF OKLAHOMA
  
CONDENSED STATEMENTS OF INCOME
  
For the Three and Nine Months Ended September 30, 2013 and 2012
  
(in thousands)
  
(Unaudited)
  
 
  
 
    
 
    
 
    
 
  
 
  
Three Months Ended
    
Nine Months Ended
  
 
  
September 30,
    
September 30,
  
 
  
2013
    
2012
    
2013
    
2012
  
REVENUES
  
 
    
 
    
 
    
 
  
Electric Generation, Transmission and Distribution
   $ 408,803     $ 364,851     $ 986,008     $ 968,683  
Sales to AEP Affiliates
     1,659       6,865       9,186       19,377  
Other Revenues
     621       1,156       2,865       2,654  
TOTAL REVENUES
     411,083       372,872       998,059       990,714  
 
                                
EXPENSES
                                
Fuel and Other Consumables Used for Electric Generation
     124,763       65,195       254,314       281,746  
Purchased Electricity for Resale
     55,915       75,719       179,405       145,983  
Purchased Electricity from AEP Affiliates
     13,129       5,870       30,168       16,328  
Other Operation
     60,566       58,975       162,032       154,834  
Maintenance
     25,071       25,685       78,396       78,863  
Depreciation and Amortization
     24,191       24,433       72,449       71,356  
Taxes Other Than Income Taxes
     11,616       10,799       33,440       32,619  
TOTAL EXPENSES
     315,251       266,676       810,204       781,729  
 
                                
OPERATING INCOME
     95,832       106,196       187,855       208,985  
 
                                
Other Income (Expense):
                                
Interest Income
     25       171       1,146       1,203  
Carrying Costs Income
     21       418       338       1,560  
Allowance for Equity Funds Used During Construction
     852       408       2,676       1,298  
Interest Expense
     (13,417 )     (13,735 )     (40,016 )     (42,212 )
 
                                
INCOME BEFORE INCOME TAX EXPENSE
     83,313       93,458       151,999       170,834  
 
                                
Income Tax Expense
     32,217       35,355       58,778       64,872  
 
                                
NET INCOME
   $ 51,096     $ 58,103     $ 93,221     $ 105,962  
 
                                
The common stock of PSO is wholly-owned by AEP.
                                
 
                                
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
  

 
140
 


PUBLIC SERVICE COMPANY OF OKLAHOMA
  
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
  
For the Three and Nine Months Ended September 30, 2013 and 2012
  
(in thousands)
  
(Unaudited)
  
 
  
 
    
 
    
 
    
 
  
 
Three Months Ended
  
Nine Months Ended
  
 
September 30,
  
September 30,
  
 
  
2013
    
2012
    
2013
    
2012
  
Net Income
   $ 51,096     $ 58,103     $ 93,221     $ 105,962  
 
                                
OTHER COMPREHENSIVE LOSS, NET OF TAXES
                                
Cash Flow Hedges, Net of Tax of $92 and $28 for the Three Months Ended
                                
September 30, 2013 and 2012, Respectively, and $319 and $250 for the Nine
                                
Months Ended September 30, 2013 and 2012, Respectively
     (172 )     (53 )     (593 )     (465 )
 
                                
TOTAL COMPREHENSIVE INCOME
   $ 50,924     $ 58,050     $ 92,628     $ 105,497  
 
                                
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
  

 
141
 


PUBLIC SERVICE COMPANY OF OKLAHOMA
  
CONDENSED STATEMENTS OF CHANGES IN
  
COMMON SHAREHOLDER'S EQUITY
  
For the Nine Months Ended September 30, 2013 and 2012
  
(in thousands)
  
(Unaudited)
  
 
  
 
    
 
    
 
    
 
    
 
  
 
    
 
    
 
    
 
    
Accumulated
    
 
  
 
  
 
    
 
    
 
    
Other
    
 
  
 
  
Common
    
Paid-in
    
Retained
    
Comprehensive
    
 
  
 
  
Stock
    
Capital
    
Earnings
    
Income (Loss)
    
Total
  
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 )
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  
 
                                        
TOTAL COMMON SHAREHOLDER'S
                                        
EQUITY – DECEMBER 31, 2012
   $ 157,230     $ 364,037     $ 388,530     $ 6,481     $ 916,278  
 
                                        
Common Stock Dividends
                     (41,250 )             (41,250 )
Net Income
                     93,221               93,221  
Other Comprehensive Loss
                             (593 )     (593 )
TOTAL COMMON SHAREHOLDER'S
                                        
EQUITY – SEPTEMBER 30, 2013
   $ 157,230     $ 364,037     $ 440,501     $ 5,888     $ 967,656  
 
                                        
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
  

 
142
 


 
PUBLIC SERVICE COMPANY OF OKLAHOMA
 
CONDENSED BALANCE SHEETS
 
ASSETS
 
September 30, 2013 and December 31, 2012
 
(in thousands)
 
(Unaudited)
 
 
 
 
 
 
 
September 30,
 
December 31,
 
 
 
2013 
 
2012 
 
CURRENT ASSETS
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 2,000 
 
$
 1,367 
 
Advances to Affiliates
 
 
 19,442 
 
 
 10,558 
 
Accounts Receivable:
 
 
 
 
 
 
 
 
Customers
 
 
 30,787 
 
 
 31,047 
 
 
Affiliated Companies
 
 
 20,448 
 
 
 24,751 
 
 
Miscellaneous
 
 
 4,409 
 
 
 6,216 
 
 
Allowance for Uncollectible Accounts
 
 
 (956)
 
 
 (872)
 
 
 
Total Accounts Receivable
 
 
 54,688 
 
 
 61,142 
 
Fuel
 
 
 18,202 
 
 
 22,085 
 
Materials and Supplies
 
 
 52,190 
 
 
 52,183 
 
Risk Management Assets
 
 
 852 
 
 
 509 
 
Deferred Income Tax Benefits
 
 
 5,713 
 
 
 7,183 
 
Accrued Tax Benefits
 
 
 10,628 
 
 
 11,812 
 
Prepayments and Other Current Assets
 
 
 6,908 
 
 
 7,633 
 
TOTAL CURRENT ASSETS
 
 
 170,623 
 
 
 174,472 
 
 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
 
Generation
 
 
 1,381,290 
 
 
 1,346,530 
 
 
Transmission
 
 
 724,125 
 
 
 706,917 
 
 
Distribution
 
 
 1,937,654 
 
 
 1,859,557 
 
Other Property, Plant and Equipment
 
 
 219,015 
 
 
 210,549 
 
Construction Work in Progress
 
 
 118,879 
 
 
 95,170 
 
Total Property, Plant and Equipment
 
 
 4,380,963 
 
 
 4,218,723 
 
Accumulated Depreciation and Amortization
 
 
 1,321,843 
 
 
 1,278,941 
 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
 
 3,059,120 
 
 
 2,939,782 
 
 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
 
Regulatory Assets
 
 
 185,856 
 
 
 202,328 
 
Long-term Risk Management Assets
 
 
 149 
 
 
 31 
 
Deferred Charges and Other Noncurrent Assets
 
 
 17,217 
 
 
 8,560 
 
TOTAL OTHER NONCURRENT ASSETS
 
 
 203,222 
 
 
 210,919 
 
 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 3,432,965 
 
$
 3,325,173 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
 
 
143
 
 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
 
CONDENSED BALANCE SHEETS
 
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
September 30, 2013 and December 31, 2012
 
(Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30,
 
December 31,
 
 
 
2013 
 
2012 
 
 
 
 
(in thousands)
 
CURRENT LIABILITIES
 
 
 
 
 
 
 
Accounts Payable:
 
 
 
 
 
 
 
 
General
 
$
 106,997 
 
$
 87,050 
 
 
Affiliated Companies
 
 
 32,646 
 
 
 36,189 
 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 34,111 
 
 
 764 
 
Risk Management Liabilities
 
 
 1,388 
 
 
 5,848 
 
Customer Deposits
 
 
 45,653 
 
 
 46,533 
 
Accrued Taxes
 
 
 55,923 
 
 
 28,024 
 
Accrued Interest
 
 
 15,383 
 
 
 12,654 
 
Regulatory Liability for Over-Recovered Fuel Costs
 
 
 144 
 
 
 7,945 
 
Other Current Liabilities
 
 
 47,311 
 
 
 50,684 
 
TOTAL CURRENT LIABILITIES
 
 
 339,556 
 
 
 275,691 
 
 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 915,715 
 
 
 949,107 
 
Long-term Risk Management Liabilities
 
 
 - 
 
 
 31 
 
Deferred Income Taxes
 
 
 814,719 
 
 
 740,676 
 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 324,329 
 
 
 344,817 
 
Employee Benefits and Pension Obligations
 
 
 33,884 
 
 
 34,906 
 
Deferred Credits and Other Noncurrent Liabilities
 
 
 37,106 
 
 
 63,667 
 
TOTAL NONCURRENT LIABILITIES
 
 
 2,125,753 
 
 
 2,133,204 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 2,465,309 
 
 
 2,408,895 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
 
Commitments and Contingencies (Note 4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
 
 
 
Common Stock – Par Value – $15 Per Share:
 
 
 
 
 
 
 
 
Authorized – 11,000,000 Shares
 
 
 
 
 
 
 
 
Issued – 10,482,000 Shares
 
 
 
 
 
 
 
 
Outstanding – 9,013,000 Shares
 
 
 157,230 
 
 
 157,230 
 
Paid-in Capital
 
 
 364,037 
 
 
 364,037 
 
Retained Earnings
 
 
 440,501 
 
 
 388,530 
 
Accumulated Other Comprehensive Income (Loss)
 
 
 5,888 
 
 
 6,481 
 
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 967,656 
 
 
 916,278 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
 3,432,965 
 
$
 3,325,173 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

 
144
 


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2013 and 2012
(in thousands)
(Unaudited)
 
 
 
 
 
 
Nine Months Ended September 30,
 
 
2013 
 
2012 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net Income
 
$
 93,221 
 
$
 105,962 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating
 
 
 
 
 
 
 
Activities:
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 72,449 
 
 
 71,356 
 
 
Deferred Income Taxes
 
 
 39,665 
 
 
 22,524 
 
 
Carrying Costs Income
 
 
 (338)
 
 
 (1,560)
 
 
Allowance for Equity Funds Used During Construction
 
 
 (2,676)
 
 
 (1,298)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 (4,984)
 
 
 3,868 
 
 
Property Taxes
 
 
 (10,177)
 
 
 (9,673)
 
 
Fuel Over/Under-Recovery, Net
 
 
 (9,201)
 
 
 40,240 
 
 
Change in Other Noncurrent Assets
 
 
 (3,175)
 
 
 10,869 
 
 
Change in Other Noncurrent Liabilities
 
 
 (13,094)
 
 
 (1,325)
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 6,454 
 
 
 10,684 
 
 
 
Fuel, Materials and Supplies
 
 
 3,876 
 
 
 (2,320)
 
 
 
Accounts Payable
 
 
 8,783 
 
 
 (11,632)
 
 
 
Accrued Taxes, Net
 
 
 37,739 
 
 
 43,313 
 
 
 
Other Current Assets
 
 
 216 
 
 
 (1,864)
 
 
 
Other Current Liabilities
 
 
 (3,780)
 
 
 (1,275)
Net Cash Flows from Operating Activities
 
 
 214,978 
 
 
 277,869 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
Construction Expenditures
 
 
 (172,602)
 
 
 (151,603)
Change in Advances to Affiliates, Net
 
 
 (8,884)
 
 
 (67,583)
Other Investing Activities
 
 
 10,657 
 
 
 1,107 
Net Cash Flows Used for Investing Activities
 
 
 (170,829)
 
 
 (218,079)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
 
 - 
 
 
 2,395 
Retirement of Long-term Debt – Nonaffiliated
 
 
 (301)
 
 
 (130)
Principal Payments for Capital Lease Obligations
 
 
 (2,558)
 
 
 (2,585)
Dividends Paid on Common Stock
 
 
 (41,250)
 
 
 (60,000)
Other Financing Activities
 
 
 593 
 
 
 139 
Net Cash Flows Used for Financing Activities
 
 
 (43,516)
 
 
 (60,181)
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 633 
 
 
 (391)
Cash and Cash Equivalents at Beginning of Period
 
 
 1,367 
 
 
 1,413 
Cash and Cash Equivalents at End of Period
 
$
 2,000 
 
$
 1,022 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 36,054 
 
$
 36,681 
Net Cash Paid for Income Taxes
 
 
 2,026 
 
 
 17,988 
Noncash Acquisitions Under Capital Leases
 
 
 4,068 
 
 
 979 
Construction Expenditures Included in Current Liabilities as of September 30,
 
 
 33,820 
 
 
 23,872 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

 
145
 

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.

 
Page
 
Number
   
Significant Accounting Matters
   162
Comprehensive Income
   162
Rate Matters
   175
Commitments, Guarantees and Contingencies
   186
Benefit Plans
   191
Business Segments
   194
Derivatives and Hedging
   195
Fair Value Measurements
   208
Income Taxes
   220
Financing Activities
   221
Variable Interest Entities
   225
Sustainable Cost Reductions
   229

 
146
 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 

 
147
 

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

EXECUTIVE OVERVIEW

Regulatory Activity

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.  As of September 30, 2013, SWEPCo’s share of incurred construction expenditures for the Turk Plant was approximately $1.8 billion, including AFUDC and capitalized interest of $328 million and related transmission costs of $118 million.  As of September 30, 2013, a provision of $173 million has been recorded for costs incurred in excess of a Texas cost cap, resulting in total capitalized expenditures of $1.6 billion.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant.  In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN.  The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market.  If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.  See “Turk Plant” section of Note 3.

2012 Texas Base Rate Case

In 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 operation and maintenance costs.  In September 2012, an Administrative Law Judge (ALJ) 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.  In May 2013, the ALJ issued a proposal for decision recommending a rate increase but found SWEPCo imprudent for failing to cancel the Turk Plant in 2010.

The PUCT rejected the ALJ’s imprudence recommendation, but during a September 2013 open meeting, the PUCT stated that it would limit the recovery of the investment in the Turk Plant by imposing a Texas jurisdictional cost cap established in the recently concluded Certificate of Convenience and Necessity (CCN) case appeal (the Texas capital cost cap).  The PUCT also provided new details on how the cost cap would be applied.  In October 2013, the PUCT issued an order with the determination that the Turk Plant Texas capital cost cap also limited SWEPCo’s recovery of AFUDC in addition to its recovery of cash construction costs.  As a result of the determination that AFUDC was to be included in the cap, in the third quarter of 2013, SWEPCo recorded an additional pretax impairment of $111 million in Asset Impairments and Other Related Charges on the statement of income.  The order approved an annual rate increase of approximately $39 million based upon a return on common equity of 9.65%.  As a result of this approval, SWEPCo retroactively applied these rates back to the end of January 2013.  The approval also provided for the following:  (a) no disallowances to the existing book investment in the Stall Plant, and (b) the exclusion, until SWEPCo files and obtains approval of a Transmission Cost Recovery Rider, of the Turk Plant transmission line investment that was not in service at the end of the test year.  Additionally, the PUCT determined that it would defer consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.  Requests for rehearing may be filed within 30 days of receipt of the PUCT order.  SWEPCo intends to file a motion for rehearing with the PUCT in late October 2013.

If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Turk Plant, transmission lines or Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.  See “2012 Texas Base Rate Case” section of Note 3.

 
148
 
2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant.  In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013.  The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund.  The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013.  In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant.  If the LPSC orders refunds based upon the pending staff review of the cost of service or prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.  See “2012 Louisiana Formula Rate Filing” section of Note 3.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC.  Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC.  As of September 30, 2013, SWEPCo has incurred $17 million in costs related to these projects.  Management intends to seek recovery of these projects from SWEPCo’s state commissions.

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 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 161.  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 230 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,
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 2,081 
 
 
 2,120 
 
 
 5,021 
 
 
 5,072 
 
Commercial
 
 1,745 
 
 
 1,764 
 
 
 4,580 
 
 
 4,718 
 
Industrial
 
 1,443 
 
 
 1,448 
 
 
 4,167 
 
 
 4,279 
 
Miscellaneous
 
 19 
 
 
 20 
 
 
 60 
 
 
 60 
Total Retail (a)
 
 5,288 
 
 
 5,352 
 
 
 13,828 
 
 
 14,129 
 
 
 
 
 
 
 
 
 
 
 
 
Wholesale
 
 2,479 
 
 
 2,108 
 
 
 7,053 
 
 
 5,987 
 
 
 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 7,767 
 
 
 7,460 
 
 
 20,881 
 
 
 20,116 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Represents energy delivered to distribution customers.

 
149
 
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,
 
 
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
(in degree days)
 
Actual - Heating (a)
 
 - 
 
 
 - 
 
 
 800 
 
 
 427 
 
Normal - Heating (b)
 
 1 
 
 
 1 
 
 
 754 
 
 
 774 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 1,418 
 
 
 1,457 
 
 
 2,137 
 
 
 2,481 
 
Normal - Cooling (b)
 
 1,397 
 
 
 1,396 
 
 
 2,155 
 
 
 2,136 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

 
150
 
Third Quarter of 2013 Compared to Third Quarter of 2012
 
  
 
  
Reconciliation of Third Quarter of 2012 to Third Quarter of 2013
  
Net Income
  
(in millions)
  
 
  
 
  
Third Quarter of 2012
   $ 89  
 
        
Changes in Gross Margin:
        
Retail Margins (a)
     46  
Off-system Sales
     2  
Transmission Revenues
     2  
Total Change in Gross Margin
     50  
 
        
Changes in Expenses and Other:
        
Other Operation and Maintenance
     1  
Asset Impairments and Other Related Charges
     (111 )
Depreciation and Amortization
     (7 )
Taxes Other Than Income Taxes
     (1 )
Other Income
     (12 )
Interest Expense
     (11 )
Total Change in Expenses and Other
     (141 )
 
        
Income Tax Expense
     10  
 
        
Third Quarter of 2013
   $ 8  
 
        
(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 $46 million primarily due to the following:
  
   
·
A $63 million increase primarily due to the Louisiana and Texas rate orders related to the Turk Plant.
  
   
This increase was partially offset by:
   
·
A $10 million decrease in municipal and cooperative revenues due to formula rate adjustments. adjustments.
   
·
A $5 million decrease primarily due to lower weather-normalized retail sales.

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

 
·
Other Operation and Maintenance expenses decreased $1 million primarily due to the following:
   
·
A $5 million decrease in distribution expenses primarily due to 2012 storm-related expenses.
   
·
A $5 million decrease in administrative and general expenses.
   
These decreases were partially offset by:
   
·
A $7 million increase in transmission expenses primarily due to increased SPP transmission services.
   
·
A $3 million increase in generation plant expenses primarily due to Turk Plant operations in addition to higher planned and unplanned plant outages.
 
·
Asset Impairments and Other Related Charges increased $111 million due to the third quarter 2013 write-off of AFUDC on the Turk Plant that was included in the Texas capital cost cap.  This write-off was in accordance with the PUCT’s September 2013 open meeting and October 2013 order.
 
·
Depreciation and Amortization expenses increased $7 million primarily due to the Turk Plant being placed in service in December 2012.
 
·
Other Income decreased $12 million primarily due to a decrease in the equity component of AFUDC as a result of completed construction of the Turk Plant in December 2012.
 
·
Interest Expense increased $11 million primarily due to a decrease in the debt component of AFUDC due to completed construction of the Turk Plant in December 2012.
 
·
Income Tax Expense decreased $10 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 the regulatory accounting treatment of state income taxes.

 
151
 
Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012
 
 
 
 
 
Reconciliation of Nine Months Ended September 30, 2012 to Nine Months Ended September 30, 2013
Net Income
(in millions)
 
 
 
 
 
Nine Months Ended September 30, 2012
 
$
 181 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
Retail Margins (a)
 
 
 71 
 
Off-system Sales
 
 
 4 
 
Transmission Revenues
 
 
 10 
 
Other Revenues
 
 
 1 
 
Total Change in Gross Margin
 
 
 86 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
Other Operation and Maintenance
 
 
 (22)
 
Asset Impairments and Other Related Charges
 
 
 (98)
 
Depreciation and Amortization
 
 
 (29)
 
Taxes Other Than Income Taxes
 
 
 (6)
 
Other Income
 
 
 (39)
 
Interest Expense
 
 
 (35)
 
Total Change in Expenses and Other
 
 
 (229)
 
 
 
 
 
 
Income Tax Expense
 
 
 12 
 
 
 
 
 
 
Nine Months Ended September 30, 2013
 
$
 50 
 
 
 
 
 
 
(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 $71 million primarily due to the following:
   
·
A $109 million increase primarily due to the Louisiana and Texas rate orders related to the Turk Plant.
   
This increase was partially offset by:
   
·
A $21 million decrease in municipal and cooperative revenues due to formula rate adjustments.
   
·
A $6 million decrease due to fuel cost adjustments.
   
·
A $6 million decrease primarily due to lower weather-normalized retail sales.
   
·
A $5 million net decrease in weather-related usage primarily due to a 14% decrease in cooling degree days, partially offset by an increase in heating degree days.
   · Margins from Off-system Sales increased $4 million primarily due to higher physical sales margins.
   · Transmission Revenues increased $10 million primarily due to rate increases for customers in the SPP region.
 
152
 

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

 
·
Other Operation and Maintenance expenses increased $22 million primarily due to the following:
   
·
A $15 million increase in transmission expenses primarily due to increased SPP transmission services.
   
·
An $11 million increase in generation plant expenses primarily due to Turk Plant operations in addition to higher planned and unplanned plant outages.
   
These increases were partially offset by:
   
·
A $2 million decrease in administrative and general expenses.
 
·
Asset Impairments and Other Related Charges increased $98 million due to the following:
   
·
 A $111 million increase due to the third quarter 2013 write-off of AFUDC on the Turk Plant that was included in the Texas capital cost cap.  This write-off was in accordance with the PUCT’s September 2013 open meeting and October 2013 order.
   
This increase was partially offset by:
     ·  A $13 million decrease due to the second quarter 2012 write-off of the additional expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap.
 
·
Depreciation and Amortization expenses increased $29 million primarily due to the Turk Plant being placed in service in December 2012.
 
·
Taxes Other Than Income Taxes increased $6 million primarily due to higher property taxes related to the Turk Plant being placed in service in December 2012.
 
·
Other Income decreased $39 million primarily due to a decrease in the equity component of AFUDC as a result of completed construction of the Turk Plant in December 2012.
 
·
Interest Expense increased $35 million primarily due to a decrease in the debt component of AFUDC due to completed construction of the Turk Plant in December 2012.
 
·
Income Tax Expense decreased $12 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 the regulatory accounting treatment of 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 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, 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 230 for a discussion of accounting pronouncements.

 
153
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
  
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
  
For the Three and Nine Months Ended September 30, 2013 and 2012
  
(in thousands)
  
(Unaudited)
  
 
  
 
  
Three Months Ended
    
Nine Months Ended
  
 
  
September 30,
    
September 30,
  
 
  
2013
    
2012
    
2013
    
2012
  
REVENUES
  
 
    
 
    
 
    
 
  
Electric Generation, Transmission and Distribution
   $ 534,196     $ 473,391     $ 1,324,325     $ 1,196,753  
Sales to AEP Affiliates
     18,296       11,098       41,935       26,945  
Other Revenues
     441       680       1,163       1,403  
TOTAL REVENUES
     552,933       485,169       1,367,423       1,225,101  
 
                                
EXPENSES
                                
Fuel and Other Consumables Used for Electric Generation
     202,024       180,991       490,447       447,233  
Purchased Electricity for Resale
     37,505       35,109       120,273       97,150  
Purchased Electricity from AEP Affiliates
     815       6,121       6,757       16,965  
Other Operation
     62,108       60,217       182,351       165,877  
Maintenance
     24,654       27,816       84,725       78,835  
Asset Impairments and Other Related Charges
     110,850       -       110,850       13,000  
Depreciation and Amortization
     41,846       35,144       132,460       103,820  
Taxes Other Than Income Taxes
     20,772       19,763       59,530       53,869  
TOTAL EXPENSES
     500,574       365,161       1,187,393       976,749  
 
                                
OPERATING INCOME
     52,359       120,008       180,030       248,352  
 
                                
Other Income (Expense):
                                
Other Income
     2,457       15,255       5,048       44,572  
Interest Expense
     (32,614 )     (21,498 )     (100,151 )     (65,210 )
 
                                
INCOME BEFORE INCOME TAX EXPENSE AND
                                
EQUITY EARNINGS
     22,202       113,765       84,927       227,714  
 
                                
Income Tax Expense
     14,935       25,229       37,057       49,206  
Equity Earnings of Unconsolidated Subsidiary
     653       682       1,825       2,007  
 
                                
NET INCOME
     7,920       89,218       49,695       180,515  
 
                                
Net Income Attributable to Noncontrolling Interest
     1,058       955       3,204       3,099  
 
                                
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON
                                
SHAREHOLDER
   $ 6,862     $ 88,263     $ 46,491     $ 177,416  
 
                                
The common stock of SWEPCo is wholly-owned by AEP.
                                
 
                                
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
  

 
154
 


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
  
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
  
For the Three and Nine Months Ended September 30, 2013 and 2012
  
(in thousands)
  
(Unaudited)
  
 
  
 
    
 
    
 
    
 
  
 
  
Three Months Ended
    
Nine Months Ended
  
 
  
September 30,
    
September 30,
  
 
  
2013
    
2012
    
2013
    
2012
  
Net Income
   $ 7,920     $ 89,218     $ 49,695     $ 180,515  
 
                                
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                                
Cash Flow Hedges, Net of Tax of $317 and $376 for the Three Months Ended
                                
September 30, 2013 and 2012, Respectively, and $902 and $367 for the
                                
Nine Months Ended September 30, 2013 and 2012, Respectively
     589       697       1,675       (682 )
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $35
                                
and $90 for the Three Months Ended September 30, 2013 and 2012,
                                
Respectively, and $103 and $269 for the Nine Months Ended September 30,
                                
2013 and 2012, Respectively
     (64 )     167       (191 )     499  
 
                                
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
     525       864       1,484       (183 )
 
                                
TOTAL COMPREHENSIVE INCOME
     8,445       90,082       51,179       180,332  
 
                                
Total Comprehensive Income Attributable to Noncontrolling Interest
     1,058       955       3,204       3,099  
 
                                
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo
                                
COMMON SHAREHOLDER
   $ 7,387     $ 89,127     $ 47,975     $ 177,233  
 
                                
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
  

 
155
 


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
  
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
  
For the Nine Months Ended September 30, 2013 and 2012
  
(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, 2011
   $ 135,660     $ 674,606     $ 1,029,915     $ (26,815 )   $ 391     $ 1,813,757  
 
                                                
Common Stock Dividends – Nonaffiliated
                                     (3,176 )     (3,176 )
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  
 
                                                
TOTAL EQUITY – DECEMBER 31, 2012
   $ 135,660     $ 674,606     $ 1,228,806     $ (17,860 )   $ 261     $ 2,021,473  
 
                                                
Common Stock Dividends
                     (93,750 )                     (93,750 )
Common Stock Dividends – Nonaffiliated
                                     (3,142 )     (3,142 )
Net Income
                     46,491               3,204       49,695  
Other Comprehensive Income
                             1,484               1,484  
TOTAL EQUITY – SEPTEMBER 30, 2013
   $ 135,660     $ 674,606     $ 1,181,547     $ (16,376 )   $ 323     $ 1,975,760  
 
                                                
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
  

 
156
 


 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
ASSETS
 
September 30, 2013 and December 31, 2012
 
(in thousands)
 
(Unaudited)
 
 
 
 
 
 
 
 
September 30,
 
December 31,
 
 
 
2013 
 
2012 
 
CURRENT ASSETS
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 17,651 
 
$
 2,036 
 
 
 
 
(September 30, 2013 Amount Includes $14,207 Related to Sabine)
 
 
 
 
 
 
Advances to Affiliates
 
 
 18,634 
 
 
 153,829 
 
Accounts Receivable:
 
 
 
 
 
 
 
 
 
Customers
 
 
 59,408 
 
 
 39,349 
 
 
 
Affiliated Companies
 
 
 26,597 
 
 
 26,288 
 
 
 
Miscellaneous
 
 
 22,350 
 
 
 35,514 
 
 
 
Allowance for Uncollectible Accounts
 
 
 (2,034)
 
 
 (2,041)
 
 
 
 
Total Accounts Receivable
 
 
 106,321 
 
 
 99,110 
 
Fuel
 
 
 
 
 
 
 
 
 
(September 30, 2013 and December 31, 2012 Amounts Include $32,992 and
 
 
 
 
 
 
 
 
 
$42,084, Respectively, Related to Sabine)
 
 
 121,443 
 
 
 134,234 
 
Materials and Supplies
 
 
 73,365 
 
 
 69,212 
 
Risk Management Assets
 
 
 402 
 
 
 695 
 
Deferred Income Tax Benefits
 
 
 99,362 
 
 
 101,403 
 
Accrued Tax Benefits
 
 
 7,015 
 
 
 9,616 
 
Regulatory Asset for Under-Recovered Fuel Costs
 
 
 21,430 
 
 
 8,527 
 
Prepayments and Other Current Assets
 
 
 18,673 
 
 
 16,489 
 
TOTAL CURRENT ASSETS
 
 
 484,296 
 
 
 595,151 
 
 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
 
 
Generation
 
 
 3,813,995 
 
 
 3,888,230 
 
 
 
Transmission
 
 
 1,141,848 
 
 
 1,115,795 
 
 
 
Distribution
 
 
 1,807,252 
 
 
 1,758,988 
 
Other Property, Plant and Equipment
 
 
 
 
 
 
 
 
 
(September 30, 2013 and December 31, 2012 Amounts Include $288,494 and
 
 
 
 
 
 
 
 
 
$287,032, Respectively, Related to Sabine)
 
 
 699,918 
 
 
 688,254 
 
Construction Work in Progress
 
 
 223,860 
 
 
 99,783 
 
Total Property, Plant and Equipment
 
 
 7,686,873 
 
 
 7,551,050 
 
Accumulated Depreciation and Amortization
 
 
 
 
 
 
 
 
 
(September 30, 2013 and December 31, 2012 Amounts Include $130,141 and
 
 
 
 
 
 
 
 
 
$116,597, Respectively, Related to Sabine)
 
 
 2,378,225 
 
 
 2,284,258 
 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
 
 5,308,648 
 
 
 5,266,792 
 
 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
 
Regulatory Assets
 
 
 375,581 
 
 
 403,278 
 
Long-term Risk Management Assets
 
 
 21 
 
 
 - 
 
Deferred Charges and Other Noncurrent Assets
 
 
 81,848 
 
 
 76,432 
 
TOTAL OTHER NONCURRENT ASSETS
 
 
 457,450 
 
 
 479,710 
 
 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 6,250,394 
 
$
 6,341,653 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.
 
 
157
 
 
 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
LIABILITIES AND EQUITY
 
September 30, 2013 and December 31, 2012
 
(Unaudited)
 
 
 
 
 
 
 
 
September 30,
 
December 31,
 
 
 
2013 
 
2012 
 
 
 
 
(in thousands)
 
CURRENT LIABILITIES
 
 
 
 
 
 
 
Accounts Payable:
 
 
 
 
 
 
 
 
 
General
 
$
 132,265 
 
$
 126,768 
 
 
 
Affiliated Companies
 
 
 39,657 
 
 
 62,835 
 
Short-term Debt – Nonaffiliated
 
 
 - 
 
 
 2,603 
 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 3,250 
 
 
 3,250 
 
Risk Management Liabilities
 
 
 296 
 
 
 1,128 
 
Customer Deposits
 
 
 55,832 
 
 
 69,393 
 
Accrued Taxes
 
 
 64,436 
 
 
 31,532 
 
Accrued Interest
 
 
 19,234 
 
 
 43,950 
 
Obligations Under Capital Leases
 
 
 17,905 
 
 
 17,599 
 
Regulatory Liability for Over-Recovered Fuel Costs
 
 
 5,562 
 
 
 16,761 
 
Other Current Liabilities
 
 
 63,921 
 
 
 64,997 
 
TOTAL CURRENT LIABILITIES
 
 
 402,358 
 
 
 440,816 
 
 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 2,039,994 
 
 
 2,042,978 
 
Deferred Income Taxes
 
 
 1,095,691 
 
 
 1,075,551 
 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 471,953 
 
 
 476,471 
 
Asset Retirement Obligations
 
 
 87,565 
 
 
 78,017 
 
Employee Benefits and Pension Obligations
 
 
 31,129 
 
 
 38,240 
 
Obligations Under Capital Leases
 
 
 104,175 
 
 
 114,161 
 
Deferred Credits and Other Noncurrent Liabilities
 
 
 41,769 
 
 
 53,946 
 
TOTAL NONCURRENT LIABILITIES
 
 
 3,872,276 
 
 
 3,879,364 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 4,274,634 
 
 
 4,320,180 
 
 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
 
Commitments and Contingencies (Note 4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY
 
 
 
 
 
 
 
Common Stock – Par Value – $18 Per Share:
 
 
 
 
 
 
 
 
 
Authorized – 7,600,000 Shares
 
 
 
 
 
 
 
 
 
Outstanding – 7,536,640 Shares
 
 
 135,660 
 
 
 135,660 
 
Paid-in Capital
 
 
 674,606 
 
 
 674,606 
 
Retained Earnings
 
 
 1,181,547 
 
 
 1,228,806 
 
Accumulated Other Comprehensive Income (Loss)
 
 
 (16,376)
 
 
 (17,860)
 
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 1,975,437 
 
 
 2,021,212 
 
 
 
 
 
 
 
 
 
Noncontrolling Interest
 
 
 323 
 
 
 261 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY
 
 
 1,975,760 
 
 
 2,021,473 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 
$
 6,250,394 
 
$
 6,341,653 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

 
158
 


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2013 and 2012
(in thousands)
(Unaudited)
 
 
 
 
 
 
Nine Months Ended September 30,
 
 
2013 
 
2012 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net Income
 
$
 49,695 
 
$
 180,515 
Adjustments to Reconcile Net Income to Net Cash Flows from
 
 
 
 
 
 
 
 Operating Activities:
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 132,460 
 
 
 103,820 
 
 
Deferred Income Taxes
 
 
 27,736 
 
 
 215,283 
 
 
Asset Impairments and Other Related Charges
 
 
 110,850 
 
 
 13,000 
 
 
Allowance for Equity Funds Used During Construction
 
 
 (4,872)
 
 
 (43,401)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 (591)
 
 
 (1,179)
 
 
Property Taxes
 
 
 (11,804)
 
 
 (10,167)
 
 
Fuel Over/Under-Recovery, Net
 
 
 (24,110)
 
 
 10,429 
 
 
Change in Other Noncurrent Assets
 
 
 21,935 
 
 
 12,522 
 
 
Change in Other Noncurrent Liabilities
 
 
 (10,203)
 
 
 25,945 
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 (7,384)
 
 
 (15,071)
 
 
 
Fuel, Materials and Supplies
 
 
 8,638 
 
 
 (27,911)
 
 
 
Accounts Payable
 
 
 (7,626)
 
 
 (13,474)
 
 
 
Accrued Taxes, Net
 
 
 36,127 
 
 
 (24,649)
 
 
 
Accrued Interest
 
 
 (24,752)
 
 
 (20,473)
 
 
 
Other Current Assets
 
 
 (1,483)
 
 
 (7,940)
 
 
 
Other Current Liabilities
 
 
 (13,770)
 
 
 (12,570)
Net Cash Flows from Operating Activities
 
 
 280,846 
 
 
 384,679 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
Construction Expenditures
 
 
 (284,650)
 
 
 (395,829)
Change in Advances to Affiliates, Net
 
 
 135,195 
 
 
 (128,227)
Other Investing Activities
 
 
 (383)
 
 
 1,240 
Net Cash Flows Used for Investing Activities
 
 
 (149,838)
 
 
 (522,816)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
 
 - 
 
 
 336,429 
Credit Facility Borrowings
 
 
 17,091 
 
 
 21,462 
Change in Advances from Affiliates, Net
 
 
 - 
 
 
 (132,473)
Retirement of Long-term Debt – Nonaffiliated
 
 
 (3,250)
 
 
 (21,625)
Credit Facility Repayments
 
 
 (19,694)
 
 
 (38,478)
Principal Payments for Capital Lease Obligations
 
 
 (13,394)
 
 
 (12,036)
Dividends Paid on Common Stock
 
 
 (93,750)
 
 
 - 
Dividends Paid on Common Stock – Nonaffiliated
 
 
 (3,142)
 
 
 (3,176)
Other Financing Activities
 
 
 746 
 
 
 3,859 
Net Cash Flows from (Used for) Financing Activities
 
 
 (115,393)
 
 
 153,962 
 
 
 
 
 
 
 
Net Increase in Cash and Cash Equivalents
 
 
 15,615 
 
 
 15,825 
Cash and Cash Equivalents at Beginning of Period
 
 
 2,036 
 
 
 801 
Cash and Cash Equivalents at End of Period
 
$
 17,651 
 
$
 16,626 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 115,627 
 
$
 74,656 
Net Cash Paid (Received) for Income Taxes
 
 
 265 
 
 
 (112,290)
Noncash Acquisitions Under Capital Leases
 
 
 3,848 
 
 
 18,560 
Construction Expenditures Included in Current Liabilities as of September 30,
 
 
 44,815 
 
 
 72,318 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

 
159
 

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.

 
Page
 
Number
   
Significant Accounting Matters
   162
Comprehensive Income
   162
Rate Matters
   175
Commitments, Guarantees and Contingencies
   186
Disposition and Impairments   190
Benefit Plans
   191
Business Segments
   194
Derivatives and Hedging
   195
Fair Value Measurements
   208
Income Taxes
   220
Financing Activities
   221
Variable Interest Entities
   225
Sustainable Cost Reductions
   229

 
160
 
 
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:

   
Page
   
Number
     
Significant Accounting Matters
APCo, I&M, OPCo, PSO, SWEPCo
   162
Comprehensive Income
APCo, I&M, OPCo, PSO, SWEPCo
   162
Rate Matters
APCo, I&M, OPCo, PSO, SWEPCo
   175
Commitments, Guarantees and Contingencies
APCo, I&M, OPCo, PSO, SWEPCo
   186
Disposition and Impairments
OPCo, SWEPCo
   190
Benefit Plans
APCo, I&M, OPCo, PSO, SWEPCo
   191
Business Segments
APCo, I&M, OPCo, PSO, SWEPCo
   194
Derivatives and Hedging
APCo, I&M, OPCo, PSO, SWEPCo
   195
Fair Value Measurements
APCo, I&M, OPCo, PSO, SWEPCo
   208
Income Taxes
APCo, I&M, OPCo, PSO, SWEPCo
   220
Financing Activities
APCo, I&M, OPCo, PSO, SWEPCo
   221
Variable Interest Entities
APCo, I&M, OPCo, PSO, SWEPCo
   225
Sustainable Cost Reductions
APCo, I&M, OPCo, PSO, SWEPCo
   229

 
161
 

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, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2012 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2012 as filed with the SEC on February 26, 2013.

Transfer of Cook Coal Terminal to AEGCo

On August 1, 2013, OPCo transferred ownership of Cook Coal Terminal to AEGCo.  Located in Metropolis, IL, Cook Coal Terminal performs coal transloading services for APCo and I&M and railcar maintenance services for APCo, I&M, PSO and SWEPCo.  The transfer of Cook Coal Terminal resulted in a decrease in OPCo’s total assets and total liabilities of $43.3 million and $40.6 million, respectively.

2.  COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2013.  All amounts in the following tables are presented net of related income taxes.
 
APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
Pension
 
 
 
 
 
 
Commodity
 
Foreign Currency
 
and OPEB
 
Total
 
 
 
(in thousands)
Balance in AOCI as of June 30, 2013
$
 197 
 
$
 2,583 
 
$
 (30,615)
 
$
 (27,835)
Change in Fair Value Recognized in AOCI
 
 (47)
 
 
 - 
 
 
 - 
 
 
 (47)
Amounts Reclassified from AOCI
 
 (184)
 
 
 253 
 
 
 359 
 
 
 428 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 (231)
 
 
 253 
 
 
 359 
 
 
 381 
Balance in AOCI as of September 30, 2013
$
 (34)
 
$
 2,836 
 
$
 (30,256)
 
$
 (27,454)
 
APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
Pension
 
 
 
 
 
 
Commodity
 
Foreign Currency
 
and OPEB
 
Total
 
 
 
(in thousands)
Balance in AOCI as of December 31, 2012
$
 (644)
 
$
 2,077 
 
$
 (31,331)
 
$
 (29,898)
Change in Fair Value Recognized in AOCI
 
 684 
 
 
 - 
 
 
 - 
 
 
 684 
Amounts Reclassified from AOCI
 
 (74)
 
 
 759 
 
 
 1,075 
 
 
 1,760 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 610 
 
 
 759 
 
 
 1,075 
 
 
 2,444 
Balance in AOCI as of September 30, 2013
$
 (34)
 
$
 2,836 
 
$
 (30,256)
 
$
 (27,454)
 
 
162
 
I&M
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
Pension
 
 
 
 
 
 
Commodity
 
Foreign Currency
 
and OPEB
 
Total
 
 
 
(in thousands)
Balance in AOCI as of June 30, 2013
$
 147 
 
$
 (16,796)
 
$
 (8,439)
 
$
 (25,088)
Change in Fair Value Recognized in AOCI
 
 (49)
 
 
 - 
 
 
 - 
 
 
 (49)
Amounts Reclassified from AOCI
 
 (117)
 
 
 410 
 
 
 174 
 
 
 467 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 (166)
 
 
 410 
 
 
 174 
 
 
 418 
Balance in AOCI as of September 30, 2013
$
 (19)
 
$
 (16,386)
 
$
 (8,265)
 
$
 (24,670)
 
I&M
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
Pension
 
 
 
 
 
 
Commodity
 
Foreign Currency
 
and OPEB
 
Total
 
 
 
(in thousands)
Balance in AOCI as of December 31, 2012
$
 (446)
 
$
 (19,647)
 
$
 (8,790)
 
$
 (28,883)
Change in Fair Value Recognized in AOCI
 
 443 
 
 
 2,248 
 
 
 - 
 
 
 2,691 
Amounts Reclassified from AOCI
 
 (16)
 
 
 1,013 
 
 
 525 
 
 
 1,522 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 427 
 
 
 3,261 
 
 
 525 
 
 
 4,213 
Balance in AOCI as of September 30, 2013
$
 (19)
 
$
 (16,386)
 
$
 (8,265)
 
$
 (24,670)
 
OPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
Pension
 
 
 
 
 
 
Commodity
 
Foreign Currency
 
and OPEB
 
Total
 
 
 
(in thousands)
Balance in AOCI as of June 30, 2013
$
 289 
 
$
 7,415 
 
$
 (166,369)
 
$
 (158,665)
Distribution of Cook Coal Terminal to Parent
 
 - 
 
 
 - 
 
 
 19,652 
 
 
 19,652 
Change in Fair Value Recognized in AOCI
 
 (86)
 
 
 - 
 
 
 - 
 
 
 (86)
Amounts Reclassified from AOCI
 
 (250)
 
 
 (339)
 
 
 2,985 
 
 
 2,396 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 (336)
 
 
 (339)
 
 
 2,985 
 
 
 2,310 
Balance in AOCI as of September 30, 2013
$
 (47)
 
$
 7,076 
 
$
 (143,732)
 
$
 (136,703)
 
OPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
Pension
 
 
 
 
 
 
Commodity
 
Foreign Currency
 
and OPEB
 
Total
 
 
 
(in thousands)
Balance in AOCI as of December 31, 2012
$
 (912)
 
$
 8,095 
 
$
 (172,908)
 
$
 (165,725)
Distribution of Cook Coal Terminal to Parent
 
 - 
 
 
 - 
 
 
 19,652 
 
 
 19,652 
Change in Fair Value Recognized in AOCI
 
 907 
 
 
 - 
 
 
 - 
 
 
 907 
Amounts Reclassified from AOCI
 
 (42)
 
 
 (1,019)
 
 
 9,524 
 
 
 8,463 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 865 
 
 
 (1,019)
 
 
 9,524 
 
 
 9,370 
Balance in AOCI as of September 30, 2013
$
 (47)
 
$
 7,076 
 
$
 (143,732)
 
$
 (136,703)
 
 
163
 
PSO
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
 
 
 
 
 
 
 
 
Interest Rate and
 
 
 
 
 
 
Commodity
 
Foreign Currency
 
Total
 
 
 
(in thousands)
Balance in AOCI as of June 30, 2013
$
 (21)
 
$
 6,081 
 
$
 6,060 
Change in Fair Value Recognized in AOCI
 
 32 
 
 
 - 
 
 
 32 
Amounts Reclassified from AOCI
 
 (14)
 
 
 (190)
 
 
 (204)
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 18 
 
 
 (190)
 
 
 (172)
Balance in AOCI as of September 30, 2013
$
 (3)
 
$
 5,891 
 
$
 5,888 
 
PSO
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
 
 
 
 
 
 
 
 
Interest Rate and
 
 
 
 
 
 
Commodity
 
Foreign Currency
 
Total
 
 
 
(in thousands)
Balance in AOCI as of December 31, 2012
$
 21 
 
$
 6,460 
 
$
 6,481 
Change in Fair Value Recognized in AOCI
 
 7 
 
 
 1 
 
 
 8 
Amounts Reclassified from AOCI
 
 (31)
 
 
 (570)
 
 
 (601)
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 (24)
 
 
 (569)
 
 
 (593)
Balance in AOCI as of September 30, 2013
$
 (3)
 
$
 5,891 
 
$
 5,888 
 
SWEPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
Pension
 
 
 
 
 
 
Commodity
 
Foreign Currency
 
and OPEB
 
Total
 
 
 
(in thousands)
Balance in AOCI as of June 30, 2013
$
 (26)
 
$
 (14,437)
 
$
 (2,438)
 
$
 (16,901)
Change in Fair Value Recognized in AOCI
 
 40 
 
 
 - 
 
 
 - 
 
 
 40 
Amounts Reclassified from AOCI
 
 (17)
 
 
 566 
 
 
 (64)
 
 
 485 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 23 
 
 
 566 
 
 
 (64)
 
 
 525 
Balance in AOCI as of September 30, 2013
$
 (3)
 
$
 (13,871)
 
$
 (2,502)
 
$
 (16,376)
 
SWEPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
Pension
 
 
 
 
 
 
Commodity
 
Foreign Currency
 
and OPEB
 
Total
 
 
 
(in thousands)
Balance in AOCI as of December 31, 2012
$
 22 
 
$
 (15,571)
 
$
 (2,311)
 
$
 (17,860)
Change in Fair Value Recognized in AOCI
 
 13 
 
 
 - 
 
 
 - 
 
 
 13 
Amounts Reclassified from AOCI
 
 (38)
 
 
 1,700 
 
 
 (191)
 
 
 1,471 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 (25)
 
 
 1,700 
 
 
 (191)
 
 
 1,484 
Balance in AOCI as of September 30, 2013
$
 (3)
 
$
 (13,871)
 
$
 (2,502)
 
$
 (16,376)

 
164
 
Reclassifications Out of Accumulated Other Comprehensive Income

The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2013.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs.  See Note 6 for additional details.
 
APCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
(Gain) Loss
 
 
 
 
 Reclassified
 
 
 
 
from AOCI
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues
 
$
 (75)
 
 
Purchased Electricity for Resale
 
 
 21 
 
 
Other Operation Expense
 
 
 (14)
 
 
Maintenance Expense
 
 
 (11)
 
 
Property, Plant and Equipment
 
 
 (15)
 
 
Regulatory Assets/(Liabilities), Net (a)
 
 
 (190)
Subtotal - Commodity
 
 
 (284)
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
Interest Expense
 
 
 390 
Subtotal - Interest Rate and Foreign Currency
 
 
 390 
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 106 
Income Tax (Expense) Credit
 
 
 37 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 69 
 
 
 
 
Amortization of Pension and OPEB
 
 
 
Prior Service Cost (Credit)
 
 
 (1,282)
Actuarial (Gains)/Losses
 
 
 1,834 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 552 
Income Tax (Expense) Credit
 
 
 193 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 359 
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 428 
 
 
165
 
APCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
(Gain) Loss
 
 
 
 
 Reclassified
 
 
 
 
from AOCI
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues
 
$
 (53)
 
 
Purchased Electricity for Resale
 
 
 47 
 
 
Other Operation Expense
 
 
 (38)
 
 
Maintenance Expense
 
 
 (29)
 
 
Property, Plant and Equipment
 
 
 (34)
 
 
Regulatory Assets/(Liabilities), Net (a)
 
 
 (9)
Subtotal - Commodity
 
 
 (116)
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
Interest Expense
 
 
 1,169 
Subtotal - Interest Rate and Foreign Currency
 
 
 1,169 
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 1,053 
Income Tax (Expense) Credit
 
 
 368 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 685 
 
 
 
 
Amortization of Pension and OPEB
 
 
 
Prior Service Cost (Credit)
 
 
 (3,847)
Actuarial (Gains)/Losses
 
 
 5,501 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 1,654 
Income Tax (Expense) Credit
 
 
 579 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 1,075 
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 1,760 
 
 
166
 
I&M
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
(Gain) Loss
 
 
 
 
Reclassified
 
 
 
 
from AOCI
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues
 
$
 (173)
 
 
Purchased Electricity for Resale
 
 
 47 
 
 
Other Operation Expense
 
 
 (8)
 
 
Maintenance Expense
 
 
 (5)
 
 
Property, Plant and Equipment
 
 
 (10)
 
 
Regulatory Assets/(Liabilities), Net (a)
 
 
 (31)
Subtotal - Commodity
 
 
 (180)
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
Interest Expense
 
 
 631 
Subtotal - Interest Rate and Foreign Currency
 
 
 631 
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 451 
Income Tax (Expense) Credit
 
 
 158 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 293 
 
 
 
 
Amortization of Pension and OPEB
 
 
 
Prior Service Cost (Credit)
 
 
 (199)
Actuarial (Gains)/Losses
 
 
 467 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 268 
Income Tax (Expense) Credit
 
 
 94 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 174 
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 467 
 
 
167
 
I&M
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
(Gain) Loss
 
 
 
 
Reclassified
 
 
 
 
from AOCI
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues
 
$
 (89)
 
 
Purchased Electricity for Resale
 
 
 115 
 
 
Other Operation Expense
 
 
 (23)
 
 
Maintenance Expense
 
 
 (14)
 
 
Property, Plant and Equipment
 
 
 (20)
 
 
Regulatory Assets/(Liabilities), Net (a)
 
 
 7 
Subtotal - Commodity
 
 
 (24)
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
Interest Expense
 
 
 1,558 
Subtotal - Interest Rate and Foreign Currency
 
 
 1,558 
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 1,534 
Income Tax (Expense) Credit
 
 
 537 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 997 
 
 
 
 
Amortization of Pension and OPEB
 
 
 
Prior Service Cost (Credit)
 
 
 (596)
Actuarial (Gains)/Losses
 
 
 1,404 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 808 
Income Tax (Expense) Credit
 
 
 283 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 525 
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 1,522 
 
 
168
 
OPCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
(Gain) Loss
 
 
 
 
Reclassified
 
 
 
 
from AOCI
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues
 
$
 (461)
 
 
Purchased Electricity for Resale
 
 
 129 
 
 
Other Operation Expense
 
 
 (20)
 
 
Maintenance Expense
 
 
 (11)
 
 
Property, Plant and Equipment
 
 
 (21)
Subtotal - Commodity
 
 
 (384)
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
Depreciation and Amortization Expense
 
 
 2 
 
 
Interest Expense
 
 
 (524)
Subtotal - Interest Rate and Foreign Currency
 
 
 (522)
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 (906)
Income Tax (Expense) Credit
 
 
 (317)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 (589)
 
 
 
 
Amortization of Pension and OPEB
 
 
 
Prior Service Cost (Credit)
 
 
 (1,451)
Actuarial (Gains)/Losses
 
 
 6,044 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 4,593 
Income Tax (Expense) Credit
 
 
 1,608 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 2,985 
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 2,396 
 
 
169
 
OPCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
(Gain) Loss
 
 
 
 
Reclassified
 
 
 
 
from AOCI
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues
 
$
 (246)
 
 
Purchased Electricity for Resale
 
 
 309 
 
 
Other Operation Expense
 
 
 (57)
 
 
Maintenance Expense
 
 
 (26)
 
 
Property, Plant and Equipment
 
 
 (44)
Subtotal - Commodity
 
 
 (64)
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
Depreciation and Amortization Expense
 
 
 5 
 
 
Interest Expense
 
 
 (1,573)
Subtotal - Interest Rate and Foreign Currency
 
 
 (1,568)
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 (1,632)
Income Tax (Expense) Credit
 
 
 (571)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 (1,061)
 
 
 
 
Amortization of Pension and OPEB
 
 
 
Prior Service Cost (Credit)
 
 
 (4,388)
Actuarial (Gains)/Losses
 
 
 19,040 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 14,652 
Income Tax (Expense) Credit
 
 
 5,128 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 9,524 
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 8,463 
 
 
170
 
PSO
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
(Gain) Loss
 
 
 
 
Reclassified
 
 
 
 
from AOCI
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 
 
 
 
Other Operation Expense
 
$
 (10)
 
 
Maintenance Expense
 
 
 (5)
 
 
Property, Plant and Equipment
 
 
 (7)
Subtotal - Commodity
 
 
 (22)
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
Interest Expense
 
 
 (292)
Subtotal - Interest Rate and Foreign Currency
 
 
 (292)
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 (314)
Income Tax (Expense) Credit
 
 
 (110)
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 (204)
 
PSO
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
(Gain) Loss
 
 
 
 
Reclassified
 
 
 
 
from AOCI
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 
 
 
 
Other Operation Expense
 
$
 (25)
 
 
Maintenance Expense
 
 
 (9)
 
 
Property, Plant and Equipment
 
 
 (14)
Subtotal - Commodity
 
 
 (48)
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
Interest Expense
 
 
 (876)
Subtotal - Interest Rate and Foreign Currency
 
 
 (876)
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 (924)
Income Tax (Expense) Credit
 
 
 (323)
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 (601)
 
 
171
 
SWEPCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
(Gain) Loss
 
 
 
 
Reclassified
 
 
 
 
from AOCI
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 
 
 
 
Other Operation Expense
 
$
 (12)
 
 
Maintenance Expense
 
 
 (7)
 
 
Property, Plant and Equipment
 
 
 (8)
Subtotal - Commodity
 
 
 (27)
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
Interest Expense
 
 
 872 
Subtotal - Interest Rate and Foreign Currency
 
 
 872 
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 845 
Income Tax (Expense) Credit
 
 
 296 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 549 
 
 
 
 
Amortization of Pension and OPEB
 
 
 
Prior Service Cost (Credit)
 
 
 (446)
Actuarial (Gains)/Losses
 
 
 348 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 (98)
Income Tax (Expense) Credit
 
 
 (34)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 (64)
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 485 
 
SWEPCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
(Gain) Loss
 
 
 
 
Reclassified
 
 
 
 
from AOCI
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 
 
 
 
Other Operation Expense
 
$
 (28)
 
 
Maintenance Expense
 
 
 (14)
 
 
Property, Plant and Equipment
 
 
 (16)
Subtotal - Commodity
 
 
 (58)
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
Interest Expense
 
 
 2,616 
Subtotal - Interest Rate and Foreign Currency
 
 
 2,616 
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 2,558 
Income Tax (Expense) Credit
 
 
 896 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 1,662 
 
 
 
 
Amortization of Pension and OPEB
 
 
 
Prior Service Cost (Credit)
 
 
 (1,338)
Actuarial (Gains)/Losses
 
 
 1,044 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 (294)
Income Tax (Expense) Credit
 
 
 (103)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 (191)
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 1,471 

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

 
172
 
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.  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)
 
 
 - 
 
 
 - 
 
 
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 
 
 
 - 
 
 
 - 
 
 
 - 
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:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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)
 
 
 - 
 
 
 - 
 
 
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 
 
 
 - 
 
 
 - 
 
 
 - 
Balance in AOCI as of September 30, 2012
 
$
 1,461 
 
$
 (20,665)
 
$
 7,911 
 
$
 6,684 
 
$
 (16,206)

 
173
 


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)
 
 
 - 
 
 
 - 
 
 
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 
 
 
 - 
 
 
 - 
 
 
 - 
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:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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)
 
 
 - 
 
 
 - 
 
 
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 
 
 
 - 
 
 
 - 
 
 
 - 
Balance in AOCI as of September 30, 2012
 
$
 1,461 
 
$
 (20,665)
 
$
 7,911 
 
$
 6,684 
 
$
 (16,206)

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

 
174
 
3.  RATE MATTERS

As discussed in the 2012 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 2012 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 2013 and updates the 2012 Annual Report.

Regulatory Assets Not Yet Being Recovered

 
 
 
 
APCo
 
 
 
 
September 30,
 
December 31,
 
 
 
 
2013 
 
2012 
Noncurrent Regulatory Assets
 
(in thousands)
Regulatory assets not yet being recovered pending future proceedings:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
Storm Related Costs
 
$
 65,206 
 
$
 94,458 
 
Virginia Environmental Rate Adjustment Clause
 
 
 28,417 
 
 
 29,320 
 
Expanded Net Energy Charge - Coal Inventory
 
 
 20,528 
 
 
 - 
 
Mountaineer Carbon Capture and Storage
 
 
 
 
 
 
 
 
Product Validation Facility
 
 
 14,155 
 
 
 14,155 
 
Dresden Plant Operating Costs
 
 
 8,358 
 
 
 8,758 
 
Transmission Agreement Phase-In
 
 
 3,313 
 
 
 2,992 
 
Mountaineer Carbon Capture and Storage
 
 
 
 
 
 
 
 
Commercial Scale Facility
 
 
 1,287 
 
 
 1,287 
 
Deferred Wind Power Costs
 
 
 - 
 
 
 5,143 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 4,246 
 
 
 1,447 
Total Regulatory Assets Not Yet Being Recovered
 
$
 145,510 
 
$
 157,560 

       
I&M
       
September 30,
  
December 31,
       
2013 
  
2012 
Noncurrent Regulatory Assets
  
(in thousands)
Regulatory assets not yet being recovered pending future proceedings:
            
                 
Regulatory Assets Currently Not Earning a Return
            
 
Under-Recovered Capacity Costs
  
$
 16,445 
  
$
 - 
 
Indiana Deferred Cook Plant Life Cycle Management Project Costs
    
 3,198 
    
 - 
 
Litigation Settlement
    
 - 
    
 11,098 
 
Mountaineer Carbon Capture and Storage
            
   
Commercial Scale Facility
    
 - 
    
 1,380 
 
Other Regulatory Asset Not Yet Being Recovered
    
 3,316 
    
 786 
Total Regulatory Assets Not Yet Being Recovered
  
$
 22,959 
  
$
 13,264 

 
175
 
 
 
 
 
OPCo
 
 
 
 
September 30,
 
December 31,
 
 
 
 
2013 
 
2012 
Noncurrent Regulatory Assets
 
(in thousands)
Regulatory assets not yet being recovered pending future proceedings:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
 
Economic Development Rider
 
$
 13,693 
 
$
 13,213 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
Storm Related Costs
 
 
 62,677 
 
 
 61,828 
 
Ormet Special Rate Recovery Mechanism
 
 
 32,344 
 
 
 5,453 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 2,669 
 
 
 30 
Total Regulatory Assets Not Yet Being Recovered
 
$
 111,383 
 
$
 80,524 

 
 
 
 
PSO
 
 
 
 
September 30,
 
December 31,
 
 
 
 
2013 
 
2012 
Noncurrent Regulatory Assets
 
(in thousands)
Regulatory assets not yet being recovered pending future proceedings:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
Storm Related Costs
 
$
 6,968 
 
$
 - 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 822 
 
 
 423 
Total Regulatory Assets Not Yet Being Recovered
 
$
 7,790 
 
$
 423 

 
 
 
 
SWEPCo
 
 
 
 
September 30,
 
December 31,
 
 
 
 
2013 
 
2012 
Noncurrent Regulatory Assets
 
(in thousands)
Regulatory assets not yet being recovered pending future proceedings:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
Rate Case Expenses
 
$
 7,539 
 
$
 4,517 
 
Mountaineer Carbon Capture and Storage
 
 
 
 
 
 
 
 
Commercial Scale Facility
 
 
 1,143 
 
 
 2,295 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 2,585 
 
 
 2,188 
Total Regulatory Assets Not Yet Being Recovered
 
$
 11,267 
 
$
 9,000 

If these costs are ultimately determined not to be recoverable, it could 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.  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.

 
176
 
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 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 reduce OPCo’s net deferred fuel costs up to the total balance.  As of September 30, 2013, OPCo’s net deferred fuel balance was $467 million, excluding unrecognized equity carrying costs.  A decision from the Supreme Court of Ohio is pending.

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.  The 2009 SEET order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm.  In January 2013, the PUCO found there was not a need for the large solar farm.  The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project by the end of 2013.  In September 2013, a proposed second phase of OPCo’s gridSMART program was filed with the PUCO which included a recommended technology solution project to satisfy this PUCO directive.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  In October 2013, the PUCO issued an order on the 2010 SEET filing.  As a result, the PUCO ordered a $7 million refund of pretax earnings to customers.  OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis.  The PUCO approved OPCo’s requests to file the SEET for 2011 and 2012 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 or in 2012 for OPCo.  Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo.

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover deferred fuel costs in 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.  In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate.  The IEU and the Ohio Consumers’ Counsel also filed appeals, regarding the PUCO decision in the PIRR proceeding, at the Supreme Court of Ohio in November 2012 arguing principally that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo’s net deferred fuel balance up to the total balance.  These intervenor appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of September 30, 2013, could reduce carrying costs by $33 million including $17 million of unrecognized equity carrying costs.  A decision from the Supreme Court of Ohio is pending.

Management is unable to predict the outcome of the unresolved litigation discussed above.  Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition.

June 2012 – May 2015 ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015, which was generally upheld in rehearing orders in January and March 2013.

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 final orders in both the ESP and corporate separation cases and extending through May 2015.  The initiation of the auction is pending the issuance of an order by the PUCO in a separate docket.  The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning June 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015.  OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015.

 
177
 
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 up to $188.88/MW day.  The RPM price is approximately $33/MW day through May 2014.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.  As of September 30, 2013, OPCo’s incurred deferred capacity costs balance of $228 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR 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 recovery of deferred capacity costs.

In January and March 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order including the implementation of the RSR.  The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel.  In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP).  In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR.

In June 2013, intervenors in the CBP docket filed recommendations that include prospective rate reductions for capacity and non-energy FAC issues.  OPCo maintains that the August 2012 ESP order fixed OPCo’s non-energy generation rates through December 31, 2014 and ordered the application of a $188.88/MW day price for capacity for non-shopping customers effective January 1, 2015.  However, intervenors maintained that OPCo’s non-energy generation rates should be reduced prior to January 1, 2015 to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned (10% prior to June 2014 and 60% for the period June 1, 2014 through December 31, 2014).  An additional proposal to prospectively offset deferred capacity costs based upon the results of the energy-only auctions was not quantified and OPCo maintains that proposal should not be adopted in light of prior PUCO orders.  Hearings related to the CBP were held at the PUCO in June and July 2013.  A decision from the PUCO is pending. 

If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its deferred capacity costs, it could reduce future net income and cash flows and impact financial condition.

Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets at net book value to AEPGenCo.  AEPGenCo will also assume the associated generation liabilities.  In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.  A decision from the Supreme Court of Ohio is pending.  In October 2013, OPCo filed an application with the PUCO to amend the corporate separation plan by permitting OPCo to retain certain rights to purchase power from OVEC.

Also in October 2012, filings at the FERC were submitted related to corporate separation.  In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AEPGenCo.  See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.

Storm Damage Recovery Rider (SDRR)

In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates.  The SDRR seeks recovery of 2012 incremental storm distribution expenses over twelve months starting with the effective date of the SDRR as approved by the PUCO.  OPCo also requested approval of a weighted average cost of capital carrying charge if recovery of these costs did not begin prior to April 2013.  In May 2013, intervenors filed comments with various recommendations including reductions in the amount of storm costs recoverable up to the amount deferred, an extended recovery period, and an additional review of the storm costs including the allocation of costs to capital.  Hearings at the PUCO are scheduled for December 2013.  As of September 30, 2013, OPCo
 
 
178
 
recorded $61 million in Regulatory Assets on the balance sheet related to 2012 storm damage.  If OPCo is not ultimately permitted to recover these storm costs, it could reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

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

In August 2012, intervenors filed an appeal 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 audit 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 with the use of a weighted average cost of capital (WACC).  The PUCO subsequently ruled that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes.  Hearings at the PUCO are scheduled for November 2013.  If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition.  See the 2009-2011 ESP section of the “Ohio Electric Security Plan Filing” related to the PUCO order in the PIRR proceeding.

Ormet

Ormet, a large aluminum company, has a contract through 2018 to purchase power from OPCo.  In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware.  In October 2013, following applications to the PUCO to amend Ormet’s power contract with OPCo, Ormet announced that they are unable to emerge from bankruptcy and are shutting down operations effective immediately.  Based upon previous PUCO rulings to provide rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider, except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet’s October and November 2012 power bills.  OPCo expects that any additional unpaid generation usage by Ormet will be recoverable as a regulatory asset through the Economic Development Rider.  As of September 30, 2013, OPCo has recorded a regulatory asset of $32 million of Ormet amounts collectible through the Economic Development Rider as a result of these special rate recovery mechanisms and amounts unpaid by Ormet.

In the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future.  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.  The PUCO did not take any action on this request.  The intervenors raised the issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.

 
179
 
To the extent amounts referenced above are not recoverable, it could 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.  As of September 30, 2013, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order.  Intervenors have filed motions with the PUCO requesting OPCo refund all collected pre-construction costs 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 could 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 constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.  As of September 30, 2013, SWEPCo’s share of incurred construction expenditures for the Turk Plant was approximately $1.8 billion, including AFUDC and capitalized interest of $328 million and related transmission costs of $118 million.  As of September 30, 2013, a provision of $173 million has been recorded for costs incurred in excess of a Texas cost cap, resulting in total capitalized expenditures of $1.6 billion.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%).  Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN.  In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN.  The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market.

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 cash construction cost, excluding 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.  See the “2012 Texas Base Rate Case” disclosure below for a discussion of a PUCT order on the Texas capital cost cap.  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 March 2013, SWEPCo and the TIEC’s petitions for review at the Supreme Court of Texas were denied and in August 2013, SWEPCo and the TIEC’s motions for rehearing at the Supreme Court of Texas were denied.

If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Turk Plant, transmission lines or Welsh Plant, Unit 2, it could reduce future net income and cash flows and 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, primarily due to the Turk Plant, 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 (approximately 33%) of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs.  The filing also (a) increased depreciation expense due to the decrease
 
 
180
 
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 and (c) included a return on and of the Stall Unit as of December 2011 and associated operation and maintenance costs.

In September 2012, an Administrative Law Judge (ALJ) 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.  In May 2013, the ALJ issued a proposal for decision recommending a rate increase but found SWEPCo imprudent for failing to cancel the Turk Plant in 2010.

The PUCT rejected the ALJ’s imprudence recommendation, but during a September 2013 open meeting, the PUCT stated that it would limit the recovery of the investment in the Turk Plant by imposing a Texas jurisdictional cost cap established in the recently concluded Certificate of Convenience and Necessity (CCN) case appeal discussed above (the Texas capital cost cap).  The PUCT also provided new details on how the cost cap would be applied.  In October 2013, the PUCT issued an order with the determination that the Turk Plant Texas capital cost cap also limited SWEPCo’s recovery of AFUDC in addition to its recovery of cash construction costs.  As a result of the determination that AFUDC was to be included in the cap, in the third quarter of 2013, SWEPCo recorded an additional pretax impairment of $111 million in Asset Impairments and Other Related Charges on the statement of income.  The order approved an annual rate increase of approximately $39 million based upon a return on common equity of 9.65%.  As a result of this approval, SWEPCo retroactively applied these rates back to the end of January 2013.  The approval also provided for the following:  (a) no disallowances to the existing book investment in the Stall Plant, and (b) the exclusion, until SWEPCo files and obtains approval of a Transmission Cost Recovery Rider, of the Turk Plant transmission line investment that was not in service at the end of the test year.  Additionally, the PUCT determined that it would defer consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.  As of September 30, 2013, the net book value of Welsh Plant, Unit 2 was $94 million, before cost of removal, including materials and supplies inventory and CWIP.  Requests for rehearing may be filed within 30 days of receipt of the PUCT order.  SWEPCo intends to file a motion for rehearing with the PUCT in late October 2013.

If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Turk Plant, transmission lines or Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant.  In February 2013, a settlement was filed and approved by the LPSC.  The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually.  The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund based on the staff review of the cost of service and the prudence review of the Turk Plant.  The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013.  In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant.  If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, 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.  In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant.

 
181
 
APCo Rate Matters

Plant Transfers

In October 2012, the AEP East Companies submitted several filings with the FERC regarding the transfer of certain generation plants within the AEP System.  See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.  In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant, comprising 1,647 MW of generating capacity presently owned by OPCo.  In June 2013, intervenors filed testimony with the WVPSC and made recommendations relating to APCo’s proposed asset transfers including the transfer of only one plant and the issuance of a Request for Proposals for any additional capacity and energy requirements.  Also in June 2013, the WVPSC staff filed testimony recommending the approval of the proposed asset transfers, with rate recognition to occur in a future base rate case, but limiting the liabilities to be transferred to the types and amounts reflected in the net book value of the assets.  In July 2013, the Virginia SCC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax.  The Virginia jurisdictional share of the disallowance is approximately $39 million.  The Virginia SCC also denied the proposed transfer of OPCo’s one-half interest in the Mitchell Plant to APCo.  APCo plans to pursue cost recovery of the transferred interest in the Amos Plant in Virginia in the 2014 biennial filing.  Management is currently evaluating the implications of this order while awaiting a final decision from the WVPSC.  Hearings were held at the WVPSC in July 2013.  In September 2013, a WVPSC staff brief advocated for the approval of the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo at the reduced value, for rate purposes, as approved by the Virginia SCC which could result in an additional $44 million disallowance related to the West Virginia and FERC jurisdictional shares of Amos Plant, Unit 3 and the denial of the proposed transfer of OPCo’s one-half interest in the Mitchell Plant to APCo.  This matter is currently pending before the WVPSC.  Any disallowance related to recovery of Amos Plant, Unit 3, as a result of Virginia SCC or WVPSC orders, would be recorded upon the transfer, expected in the fourth quarter of 2013.  If APCo and WPCo are not ultimately permitted to recover their incurred costs, it could reduce future net income and cash flows and impact financial condition.    

APCo IGCC Plant

As of September 30, 2013, 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 $10 million applicable to its Virginia jurisdiction.  If the costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs effective February 2014 over a one-year period.  In March 2013, the environmental RAC surcharge expired related to the collection of 2009 and 2010 environmental compliance costs.  In August 2013, a settlement agreement was submitted to the Virginia SCC which recommended approval of an environmental RAC to recover $38 million of the 2012 and 2011 environmental compliance costs.  In September 2013, the Hearing Examiner recommended the approval of the settlement agreement.  An order is expected from the Virginia SCC no later than November 2013.  APCo has deferred $28 million as of September 30, 2013 for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $10 million of unrecognized equity carrying costs.  If the Virginia SCC were to disallow any portion of the environmental RAC, it could reduce future net income and cash flows.

2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing

In March 2013, APCo filed with the Virginia SCC for an increase in its generation RAC revenues of $12 million for a total of $38 million annually to collect costs related to the Dresden Plant.  In August 2013, a settlement agreement was submitted to the Virginia SCC which recommended approval of an increase in the generation RAC to $37 million annually if the proposed merger of WPCo into APCo occurs by January 1, 2014 or an increase to $39 million if the proposed merger does not occur by January 1, 2014.  Per the settlement agreement, the generation RAC increase is to be effective no later than March 2014 for a period of one year at which time the component to
 
 
182
 
collect an under-recovery of approximately $9 million will cease and the remaining component to recover on-going Dresden Plant costs will continue.  In October 2013, the Hearing Examiner recommended the approval of the settlement agreement.  An order is expected from the Virginia SCC no later than December 2013.  APCo has deferred $6 million as of September 30, 2013 for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $4 million of unrecognized equity carrying costs.  If the Virginia SCC were to disallow any portion of the generation RAC, it could reduce future net income and cash flows.

2013 West Virginia Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation which allows the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred ENEC balances and other ENEC-related assets.  In August 2012, APCo and WPCo filed a request with the WVPSC for a financing order to securitize a total of $422 million related to the December 2011 under-recovered ENEC deferral balance including other ENEC-related assets of $13 million and related future financing costs of $7 million.  Upon completion of the securitization, APCo would offset its current ENEC rates by an amount to recover the securitized balance over the securitization period.  In March 2013, APCo, WPCo and intervenors filed a settlement agreement with the WVPSC which recommended the WVPSC authorize APCo to securitize $376 million plus upfront financing costs.  In September 2013, the WVPSC approved the settlement agreement.  The securitization bonds are expected to be issued in the fourth quarter of 2013.

In April 2013, APCo and WPCo filed to keep total rates unchanged with a portion of the ENEC to be specifically identified for the amount to be securitized in accordance with the proposed securitization settlement agreement.  The remaining ENEC rate is proposed to include (a) the proposed transfer of certain generation facilities from OPCo and the APCo/WPCo merger, (b) construction surcharges and (c) ongoing ENEC costs.  In August 2013, the WVPSC approved a settlement that includes (a) a $56 million reduction in ENEC revenues, offset by a $6 million annual increase in construction surcharges, effective September 2013 and subject to true-up, (b) an agreement to file a base case no later than June 2014 and (c) the deferral of $21 million from the ENEC recovery balance with the ability to include that amount in the ENEC recovery balance upon reaching certain coal inventory levels at the Amos Plant.

As of September 30, 2013, APCo’s ENEC under-recovery balance of $281 million, net of 2012 and 2013 over-recovery, was recorded in Regulatory Assets on the balance sheet, excluding $2 million of unrecognized equity carrying costs and $14 million of other ENEC-related assets.

Virginia Storm Costs

In March 2013, due to the 2013 enactment of a Virginia law, APCo wrote off $30 million of previously deferred 2012 Virginia storm costs.  The change in law affected the test years to be included in APCo's next biennial Virginia base rate filing in March 2014 and the determination of how these costs are treated in the Virginia jurisdictional biennial earnings test for 2012 and 2013.  The estimated 2013 earnings component will be reviewed quarterly to determine if any storm costs can be deferred.  As of September 30, 2013, there were no deferrals of Virginia storm costs incurred in 2012 or 2013.  If this quarterly test allows APCo to defer previously expensed storm costs for future recovery, it could increase future net income and cash flows.

WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting authority to merge WPCo into APCo.  In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC and in April 2013, the FERC approved the merger.  Also in December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval of the transfers at net book value to APCo of OPCo’s two-thirds interest in Amos Plant, Unit 3 and OPCo’s one-half interest in the Mitchell Plant.  In June 2013, the WVPSC issued an order consolidating the merger case with APCo’s plant asset transfer case.  Also in June 2013, WVPSC staff filed testimony that included a recommendation that the WVPSC approve the proposed merger.  Hearings were held at the WVPSC in July 2013.  These matters are pending before the WVPSC.  In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of OPCo’s one-half interest in the Mitchell Plant to APCo.  Although the Virginia SCC authorized the merger of WPCo into APCo, denial of the Mitchell Plant ownership transfer means there will be insufficient generation to serve the merged company.  Management intends to review the feasibility of the merger once the WVPSC issues an order in the consolidated cases.  See the “Plant Transfers” section of APCo Rate Matters and the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.

 
183
 
PSO Rate Matters

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES), Unit 4 in 2016 and additional environmental controls on NES, Unit 3 to continue operations through 2026.  As of September 30, 2013, the net book values of NES, Units 3 and 4 were $182 million and $101 million, respectively, before cost of removal, including materials and supplies inventory and CWIP.  In August 2013, the OCC dismissed PSO’s environmental compliance plan case without prejudice but will permit PSO to seek recovery in a future proceeding.  PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan.  If PSO is ultimately not permitted to fully recover its net book value of NES, Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%.  In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates from $85 million to $92 million.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed a request for reconsideration with the IURC, which was denied.  Also in March 2013, the OUCC filed an appeal of the order with the Indiana Court of Appeals.  In September 2013, the OUCC filed a brief on appeal that included objections to the inclusion of a prepaid pension asset in rate base, the use of an end-of-test-year amount for materials and supplies instead of a thirteen-month average and the application of an “outdated” capital structure.  If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of September 30, 2013, I&M has incurred $285 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery in a base rate case.  I&M was granted recovery through an LCM rider which will be determined by a proceeding in the fourth quarter of 2013 and semi-annual proceedings thereafter.  The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in its rates.   In October 2013, I&M filed an application with the IURC for LCM rider rates to be effective January 2014.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to certain projects effective January 2013 until these costs are included in rates.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

 
184
 
Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a Dry Sorbent Injection system.  The estimated cost of the CCT Project was $285 million, excluding AFUDC to be shared equally between I&M and AEGCo.  The application requested deferral treatment of any unrecovered carrying costs incurred during construction and incremental post in-service depreciation expense and operation and maintenance expenses until such costs are recognized and recovered in a rider.  I&M also requested cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism.

In July 2013, a settlement agreement was filed with the IURC.  The settlement agreement includes the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s ownership share of $129 million.  The settlement agreement specifies that 80% of the recoverable I&M direct ownership share of CCT Project costs will be recovered through a Federal Mandate Rider with the remaining 20% deferred until rates are established in a subsequent rate case.  If the IURC approves the settlement agreement, I&M’s Indiana allocated share of the CCT Project costs received in the form of purchased power from AEGCo will be recovered in subsequent I&M rate cases.  A hearing was held at the IURC in August 2013 and a decision is expected by November 2013.  As of September 30, 2013, I&M has incurred costs of $48 million related to the CCT Project, including AFUDC.  If I&M is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows.

Tanners Creek Plant, Units 1 - 4

In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations.  In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas.   I&M is currently recovering the net book value of Tanners Creek Plant, Units 1-4 in base rates, and plans to seek recovery of all of the plant’s retirement related costs in its next Indiana and Michigan base rate cases.  As of September 30, 2013, the combined net book value of Tanners Creek Plant, Units 1-4 was $342 million, before cost of removal, including materials and supplies inventory and CWIP.  If I&M is ultimately not permitted to fully recover its net book value of Tanners Creek Plant, Units 1-4, it could reduce future net income and cash flows and impact financial condition.

FERC Rate Matters

Corporate Separation and Termination of Interconnection Agreement – Affecting APCo, I&M and OPCo

In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations.  The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets to a new wholly-owned company, AEPGenCo.  The AEP East Companies also requested FERC approval to transfer at NBV OPCo’s current two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests (780 MW each).  These transfers are proposed to be effective December 31, 2013.  In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AEPGenCo, the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo and the merger of APCo and WPCo.  In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo.  OPCo has contested the petition for rehearing, which remains pending before the FERC.  Similar asset transfer filings have been made at the Virginia SCC and the WVPSC.  See the “Plant Transfers” section of APCo Rate Matters.

Additionally, the AEP East Companies requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  Under the PCA, APCo and I&M would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies.  Further, the PCA allows, but does not obligate, APCo and I&M to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.  Intervenors have opposed
 
 
185
 
several of these filings.  The AEP East Companies responded to intervenor comments and filed a revised PCA at the FERC in March 2013.  The revised PCA included certain clarifying wording changes that have been agreed upon by intervenors.  A decision is pending at the FERC.

In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by recent orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation.  See the “Plant Transfers” section of APCo Rate Matters for a discussion of the Virginia SCC order.  

If APCo and/or I&M experience decreases in revenues or increases in expenses as a result of changes to their relationship with affiliates 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.

4.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business.  In addition, their business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements.  The Commitments, Guarantees and Contingencies note within the 2012 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 revolving credit facilities totaling $3.5 billion, under which up to $1.2 billion may be issued as letters of credit.  As of September 30, 2013, the maximum future payments for letters of credit issued under the revolving credit facilities were as follows:

Company
 
Amount
 
Maturity
 
 
(in thousands)
 
 
I&M
 
$
 150 
 
March 2014
OPCo
 
 
 3,081 
 
June 2014
SWEPCo
 
 
 4,448 
 
March 2014

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 2014 to March 2015 
I&M
 
 
77,000 
 
 
 77,886 
 
March 2015
OPCo
 
 
50,000 
 
 
 50,575 
 
July 2014

 
186
 
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 completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation.  As of September 30, 2013, SWEPCo has collected approximately $63 million through a rider for final mine closure and reclamation costs, of which $13 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $50 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed balance sheets.

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

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

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of September 30, 2013, 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 power purchase 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, 2013, 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
 
$
 3,630 
I&M
 
 
 2,481 
OPCo
 
 
 4,505 
PSO
 
 
 1,204 
SWEPCo
 
 
 2,441 

 
187
 
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 $14 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2013.

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 83% 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 $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, management believes that the fair value would produce a sufficient sales price to avoid any loss.

ENVIRONMENTAL CONTINGENCIES

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

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing.  An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place.  Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision.  The petition was denied in January 2011.  Plaintiffs refiled their complaint in federal district court.  The court ordered all defendants to respond to the refiled complaints in October 2011.  In March 2012, the court granted the defendants’ motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations.  In May 2013, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court’s dismissal of the complaint.  The plaintiffs did not appeal to the U.S. Supreme Court.

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.  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 filed seeking further review in the U.S. Supreme Court.  In May 2013, the U.S. Supreme Court denied the plaintiffs’ request for review.
 
 
188
 
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 reserve is approximately $10 million.  As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ.  Management cannot predict the amount of additional cost, if any.

NUCLEAR CONTINGENCIES – AFFECTING I&M

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

Nuclear Incident Insurance

Prior to April 2013, I&M carried insurance coverage for a nuclear or nonnuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion.  Effective April 2013, insurance coverage for a nonnuclear incident at the Cook Plant was reduced to $1.7 billion.  In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition.

OPERATIONAL CONTINGENCIES

Rockport Plant Litigation – Affecting I&M

In July 2013, the Wilmington Trust Company filed a complaint in Federal Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.  In October 2013, management filed a motion to dismiss the case.  Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

 
189
 
5.  DISPOSITION AND IMPAIRMENTS

DISPOSITION

2013

Conesville Coal Preparation Plant – Affecting OPCo

In April 2013, OPCo closed on the sale of its Conesville Coal Preparation Plant.  This sale did not have a significant impact on OPCo’s financial statements.

IMPAIRMENTS

2013

Turk Plant – Affecting SWEPCo

In the third quarter of 2013, SWEPCo recorded a pretax write-off of $111 million in Asset Impairments and Other Related Charges on the statement of income related to AFUDC on the Turk Plant that was included in the Texas capital cost cap.  See the “2012 Texas Base Rate Case” section of Note 3.

Muskingum River Plant, Unit 5 – Affecting OPCo

In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including OPCo’s 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant.  Under the modification to the consent decree, OPCo has the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017.  In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, management re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project, which would have extended the useful life of MR5, is remote.  As a result, management completed an impairment analysis and concluded that MR5 was impaired.  Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit.  In the second quarter of 2013, OPCo recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory.  Management expects to retire the plant in 2015.

2012

Turk Plant – Affecting SWEPCo

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

 
190
 
6.  BENEFIT PLANS

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

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2013 and 2012:

APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in thousands)
Service Cost
$
 1,543 
 
$
 1,892 
 
$
 641 
 
$
 1,346 
Interest Cost
 
 6,916 
 
 
 7,553 
 
 
 3,363 
 
 
 4,616 
Expected Return on Plan Assets
 
 (9,260)
 
 
 (10,486)
 
 
 (4,537)
 
 
 (4,188)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 - 
 
 
 201 
Amortization of Prior Service Cost (Credit)
 
 49 
 
 
 118 
 
 
 (2,512)
 
 
 (716)
Amortization of Net Actuarial Loss
 
 6,256 
 
 
 5,085 
 
 
 3,063 
 
 
 2,631 
Net Periodic Benefit Cost
$
 5,504 
 
$
 4,162 
 
$
 18 
 
$
 3,890 

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in thousands)
Service Cost
$
 4,628 
 
$
 5,674 
 
$
 1,924 
 
$
 4,040 
Interest Cost
 
 20,747 
 
 
 22,659 
 
 
 10,090 
 
 
 13,847 
Expected Return on Plan Assets
 
 (27,780)
 
 
 (31,458)
 
 
 (13,610)
 
 
 (12,564)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 - 
 
 
 601 
Amortization of Prior Service Cost (Credit)
 
 148 
 
 
 356 
 
 
 (7,537)
 
 
 (2,147)
Amortization of Net Actuarial Loss
 
 18,769 
 
 
 15,254 
 
 
 9,187 
 
 
 7,894 
Net Periodic Benefit Cost
$
 16,512 
 
$
 12,485 
 
$
 54 
 
$
 11,671 

 
191
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in thousands)
Service Cost
$
 2,183 
 
$
 2,477 
 
$
 804 
 
$
 1,655 
Interest Cost
 
 6,025 
 
 
 6,562 
 
 
 2,056 
 
 
 3,196 
Expected Return on Plan Assets
 
 (8,206)
 
 
 (9,392)
 
 
 (3,295)
 
 
 (3,212)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 - 
 
 
 33 
Amortization of Prior Service Cost (Credit)
 
 49 
 
 
 101 
 
 
 (2,356)
 
 
 (595)
Amortization of Net Actuarial Loss
 
 5,422 
 
 
 4,392 
 
 
 1,882 
 
 
 1,762 
Net Periodic Benefit Cost (Credit)
$
 5,473 
 
$
 4,140 
 
$
 (909)
 
$
 2,839 

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in thousands)
Service Cost
$
 6,551 
 
$
 7,431 
 
$
 2,414 
 
$
 4,965 
Interest Cost
 
 18,075 
 
 
 19,684 
 
 
 6,166 
 
 
 9,589 
Expected Return on Plan Assets
 
 (24,619)
 
 
 (28,175)
 
 
 (9,887)
 
 
 (9,635)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 - 
 
 
 99 
Amortization of Prior Service Cost (Credit)
 
 146 
 
 
 305 
 
 
 (7,066)
 
 
 (1,787)
Amortization of Net Actuarial Loss
 
 16,266 
 
 
 13,177 
 
 
 5,645 
 
 
 5,287 
Net Periodic Benefit Cost (Credit)
$
 16,419 
 
$
 12,422 
 
$
 (2,728)
 
$
 8,518 

 
192
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in thousands)
Service Cost
$
 2,362 
 
$
 2,751 
 
$
 1,028 
 
$
 2,187 
Interest Cost
 
 10,268 
 
 
 11,298 
 
 
 4,100 
 
 
 6,047 
Expected Return on Plan Assets
 
 (15,103)
 
 
 (17,100)
 
 
 (6,221)
 
 
 (5,639)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 - 
 
 
 26 
Amortization of Prior Service Cost (Credit)
 
 71 
 
 
 186 
 
 
 (3,219)
 
 
 (969)
Amortization of Net Actuarial Loss
 
 9,287 
 
 
 7,610 
 
 
 3,761 
 
 
 3,418 
Net Periodic Benefit Cost (Credit)
$
 6,885 
 
$
 4,745 
 
$
 (551)
 
$
 5,070 

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in thousands)
Service Cost
$
 7,107 
 
$
 8,253 
 
$
 3,627 
 
$
 6,561 
Interest Cost
 
 30,852 
 
 
 33,895 
 
 
 12,994 
 
 
 18,142 
Expected Return on Plan Assets
 
 (45,386)
 
 
 (51,301)
 
 
 (18,698)
 
 
 (16,917)
Amortization of Transition Obligation
 
 - 
 
 
 - 
 
 
 - 
 
 
 78 
Amortization of Prior Service Cost (Credit)
 
 212 
 
 
 557 
 
 
 (9,680)
 
 
 (2,905)
Amortization of Net Actuarial Loss
 
 27,905 
 
 
 22,830 
 
 
 11,843 
 
 
 10,252 
Net Periodic Benefit Cost
$
 20,690 
 
$
 14,234 
 
$
 86 
 
$
 15,211 

 
193
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in thousands)
Service Cost
$
 1,391 
 
$
 1,487 
 
$
 343 
 
$
 709 
Interest Cost
 
 2,748 
 
 
 3,076 
 
 
 948 
 
 
 1,449 
Expected Return on Plan Assets
 
 (3,919)
 
 
 (4,503)
 
 
 (1,522)
 
 
 (1,480)
Amortization of Prior Service Cost (Credit)
 
 75 
 
 
 (237)
 
 
 (1,072)
 
 
 (270)
Amortization of Net Actuarial Loss
 
 2,461 
 
 
 2,051 
 
 
 869 
 
 
 797 
Net Periodic Benefit Cost (Credit)
$
 2,756 
 
$
 1,874 
 
$
 (434)
 
$
 1,205 

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in thousands)
Service Cost
$
 4,172 
 
$
 4,463 
 
$
 1,029 
 
$
 2,127 
Interest Cost
 
 8,245 
 
 
 9,226 
 
 
 2,844 
 
 
 4,348 
Expected Return on Plan Assets
 
 (11,756)
 
 
 (13,511)
 
 
 (4,566)
 
 
 (4,441)
Amortization of Prior Service Cost (Credit)
 
 223 
 
 
 (711)
 
 
 (3,217)
 
 
 (809)
Amortization of Net Actuarial Loss
 
 7,383 
 
 
 6,154 
 
 
 2,607 
 
 
 2,391 
Net Periodic Benefit Cost (Credit)
$
 8,267 
 
$
 5,621 
 
$
 (1,303)
 
$
 3,616 

SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in thousands)
Service Cost
$
 1,752 
 
$
 1,775 
 
$
 424 
 
$
 831 
Interest Cost
 
 2,864 
 
 
 3,134 
 
 
 1,075 
 
 
 1,669 
Expected Return on Plan Assets
 
 (4,126)
 
 
 (4,717)
 
 
 (1,720)
 
 
 (1,699)
Amortization of Prior Service Cost (Credit)
 
 87 
 
 
 (198)
 
 
 (1,289)
 
 
 (234)
Amortization of Net Actuarial Loss
 
 2,553 
 
 
 2,083 
 
 
 982 
 
 
 915 
Net Periodic Benefit Cost (Credit)
$
 3,130 
 
$
 2,077 
 
$
 (528)
 
$
 1,482 

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in thousands)
Service Cost
$
 5,258 
 
$
 5,324 
 
$
 1,270 
 
$
 2,493 
Interest Cost
 
 8,591 
 
 
 9,403 
 
 
 3,226 
 
 
 5,005 
Expected Return on Plan Assets
 
 (12,381)
 
 
 (14,150)
 
 
 (5,160)
 
 
 (5,096)
Amortization of Prior Service Cost (Credit)
 
 262 
 
 
 (595)
 
 
 (3,867)
 
 
 (700)
Amortization of Net Actuarial Loss
 
 7,660 
 
 
 6,248 
 
 
 2,946 
 
 
 2,744 
Net Periodic Benefit Cost (Credit)
$
 9,390 
 
$
 6,230 
 
$
 (1,585)
 
$
 4,446 

7.  BUSINESS SEGMENTS

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

 
194
 
8.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

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 and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options.  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.

 
195
 
The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of September 30, 2013 and December 31, 2012:

Notional Volume of Derivative Instruments
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Primary Risk
 
Unit of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exposure
 
Measure
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
Commodity:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Power
 
MWhs
 
 
 75,861 
 
 
 49,918 
 
 
 104,093 
 
 
 8 
 
 
 10 
 
Coal
 
Tons
 
 
 282 
 
 
 3,980 
 
 
 813 
 
 
 2,075 
 
 
 1,229 
 
Natural Gas
 
MMBtus
 
 
 4,121 
 
 
 2,711 
 
 
 5,654 
 
 
 - 
 
 
 - 
 
Heating Oil and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
 
Gallons
 
 
 981 
 
 
 484 
 
 
 1,155 
 
 
 491 
 
 
 603 
 
Interest Rate
 
USD
 
$
 16,501 
 
$
 10,858 
 
$
 22,642 
 
$
 - 
 
$
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign Currency
 
USD
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notional Volume of Derivative Instruments
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Primary Risk
 
Unit of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exposure
 
Measure
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
Commodity:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Power
 
MWhs
 
 
 94,059 
 
 
 64,791 
 
 
 132,188 
 
 
 - 
 
 
 - 
 
Coal
 
Tons
 
 
 1,401 
 
 
 2,711 
 
 
 3,033 
 
 
 1,980 
 
 
 1,312 
 
Natural Gas
 
MMBtus
 
 
 10,077 
 
 
 6,922 
 
 
 14,163 
 
 
 - 
 
 
 - 
 
Heating Oil and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
 
Gallons
 
 
 1,050 
 
 
 532 
 
 
 1,260 
 
 
 616 
 
 
 585 
 
Interest Rate
 
USD
 
$
 24,146 
 
$
 16,584 
 
$
 33,934 
 
$
 - 
 
$
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign Currency
 
USD
 
$
 - 
 
$
 200,000 
 
$
 - 
 
$
 - 
 
$
 - 

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.

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
 
 
196
 
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, 2013 and December 31, 2012 condensed 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, 2013
 
December 31, 2012
 
 
 
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
 
$
 116 
 
$
 5,608 
 
$
 1,262 
 
$
 11,029 
I&M
 
 
 76 
 
 
 3,688 
 
 
 867 
 
 
 7,576 
OPCo
 
 
 159 
 
 
 7,693 
 
 
 1,774 
 
 
 15,500 
PSO
 
 
 - 
 
 
 7 
 
 
 - 
 
 
 - 
SWEPCo
 
 
 - 
 
 
 8 
 
 
 - 
 
 
 - 

 
197
 

The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of September 30, 2013 and December 31, 2012:
 
APCo
Fair Value of Derivative Instruments
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
68,593 
 
$
233 
 
$
- 
 
$
68,826 
 
$
(44,276)
 
$
24,550 
Long-term Risk Management Assets
 
 
32,501 
 
 
226 
 
 
- 
 
 
32,727 
 
 
(11,888)
 
 
20,839 
Total Assets
 
 
101,094 
 
 
459 
 
 
- 
 
 
101,553 
 
 
(56,164)
 
 
45,389 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
59,793 
 
 
567 
 
 
- 
 
 
60,360 
 
 
(48,719)
 
 
11,641 
Long-term Risk Management Liabilities
 
 
25,003 
 
 
15 
 
 
- 
 
 
25,018 
 
 
(12,937)
 
 
12,081 
Total Liabilities
 
 
84,796 
 
 
582 
 
 
- 
 
 
85,378 
 
 
(61,656)
 
 
23,722 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
16,298 
 
$
(123)
 
$
- 
 
$
16,175 
 
$
5,492 
 
$
21,667 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
127,645 
 
$
338 
 
$
- 
 
$
127,983 
 
$
(97,023)
 
$
30,960 
Long-term Risk Management Assets
 
 
60,498 
 
 
215 
 
 
- 
 
 
60,713 
 
 
(26,353)
 
 
34,360 
Total Assets
 
 
188,143 
 
 
553 
 
 
- 
 
 
188,696 
 
 
(123,376)
 
 
65,320 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
119,430 
 
 
1,182 
 
 
- 
 
 
120,612 
 
 
(103,914)
 
 
16,698 
Long-term Risk Management Liabilities
 
 
47,281 
 
 
424 
 
 
- 
 
 
47,705 
 
 
(29,229)
 
 
18,476 
Total Liabilities
 
 
166,711 
 
 
1,606 
 
 
- 
 
 
168,317 
 
 
(133,143)
 
 
35,174 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
21,432 
 
$
(1,053)
 
$
- 
 
$
20,379 
 
$
9,767 
 
$
30,146 

 
198
 


I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
44,988 
 
$
149 
 
$
- 
 
$
45,137 
 
$
(28,987)
 
$
16,150 
Long-term Risk Management Assets
 
 
21,432 
 
 
149 
 
 
- 
 
 
21,581 
 
 
(7,848)
 
 
13,733 
Total Assets
 
 
66,420 
 
 
298 
 
 
- 
 
 
66,718 
 
 
(36,835)
 
 
29,883 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
40,809 
 
 
370 
 
 
- 
 
 
41,179 
 
 
(31,911)
 
 
9,268 
Long-term Risk Management Liabilities
 
 
16,836 
 
 
7 
 
 
- 
 
 
16,843 
 
 
(8,536)
 
 
8,307 
Total Liabilities
 
 
57,645 
 
 
377 
 
 
- 
 
 
58,022 
 
 
(40,447)
 
 
17,575 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
8,775 
 
$
(79)
 
$
- 
 
$
8,696 
 
$
3,612 
 
$
12,308 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
93,268 
 
$
220 
 
$
- 
 
$
93,488 
 
$
(66,514)
 
$
26,974 
Long-term Risk Management Assets
 
 
41,553 
 
 
148 
 
 
- 
 
 
41,701 
 
 
(18,132)
 
 
23,569 
Total Assets
 
 
134,821 
 
 
368 
 
 
- 
 
 
135,189 
 
 
(84,646)
 
 
50,543 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
82,433 
 
 
807 
 
 
19,524 
 
 
102,764 
 
 
(71,247)
 
 
31,517 
Long-term Risk Management Liabilities
 
 
33,714 
 
 
292 
 
 
- 
 
 
34,006 
 
 
(20,108)
 
 
13,898 
Total Liabilities
 
 
116,147 
 
 
1,099 
 
 
19,524 
 
 
136,770 
 
 
(91,355)
 
 
45,415 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
18,674 
 
$
(731)
 
$
(19,524)
 
$
(1,581)
 
$
6,709 
 
$
5,128 

 
199
 


OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
96,628 
 
$
315 
 
$
- 
 
$
96,943 
 
$
(62,765)
 
$
34,178 
Long-term Risk Management Assets
 
 
44,597 
 
 
310 
 
 
- 
 
 
44,907 
 
 
(16,313)
 
 
28,594 
Total Assets
 
 
141,225 
 
 
625 
 
 
- 
 
 
141,850 
 
 
(79,078)
 
 
62,772 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
84,519 
 
 
774 
 
 
- 
 
 
85,293 
 
 
(68,862)
 
 
16,431 
Long-term Risk Management Liabilities
 
 
34,309 
 
 
18 
 
 
- 
 
 
34,327 
 
 
(17,750)
 
 
16,577 
Total Liabilities
 
 
118,828 
 
 
792 
 
 
- 
 
 
119,620 
 
 
(86,612)
 
 
33,008 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
22,397 
 
$
(167)
 
$
- 
 
$
22,230 
 
$
7,534 
 
$
29,764 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
183,064 
 
$
464 
 
$
- 
 
$
183,528 
 
$
(139,215)
 
$
44,313 
Long-term Risk Management Assets
 
 
85,023 
 
 
303 
 
 
- 
 
 
85,326 
 
 
(37,038)
 
 
48,288 
Total Assets
 
 
268,087 
 
 
767 
 
 
- 
 
 
268,854 
 
 
(176,253)
 
 
92,601 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
171,397 
 
 
1,658 
 
 
- 
 
 
173,055 
 
 
(148,900)
 
 
24,155 
Long-term Risk Management Liabilities
 
 
66,448 
 
 
596 
 
 
- 
 
 
67,044 
 
 
(41,079)
 
 
25,965 
Total Liabilities
 
 
237,845 
 
 
2,254 
 
 
- 
 
 
240,099 
 
 
(189,979)
 
 
50,120 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
30,242 
 
$
(1,487)
 
$
- 
 
$
28,755 
 
$
13,726 
 
$
42,481 

 
200
 


PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
1,394 
 
$
13 
 
$
- 
 
$
1,407 
 
$
(555)
 
$
852 
Long-term Risk Management Assets
 
 
149 
 
 
- 
 
 
- 
 
 
149 
 
 
- 
 
 
149 
Total Assets
 
 
1,543 
 
 
13 
 
 
- 
 
 
1,556 
 
 
(555)
 
 
1,001 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
1,931 
 
 
12 
 
 
- 
 
 
1,943 
 
 
(555)
 
 
1,388 
Long-term Risk Management Liabilities
 
 
- 
 
 
7 
 
 
- 
 
 
7 
 
 
(7)
 
 
- 
Total Liabilities
 
 
1,931 
 
 
19 
 
 
- 
 
 
1,950 
 
 
(562)
 
 
1,388 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
(388)
 
$
(6)
 
$
- 
 
$
(394)
 
$
7 
 
$
(387)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
1,657 
 
$
42 
 
$
- 
 
$
1,699 
 
$
(1,190)
 
$
509 
Long-term Risk Management Assets
 
 
- 
 
 
- 
 
 
- 
 
 
- 
 
 
31 
 
 
31 
Total Assets
 
 
1,657 
 
 
42 
 
 
- 
 
 
1,699 
 
 
(1,159)
 
 
540 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
7,021 
 
 
17 
 
 
- 
 
 
7,038 
 
 
(1,190)
 
 
5,848 
Long-term Risk Management Liabilities
 
 
- 
 
 
- 
 
 
- 
 
 
- 
 
 
31 
 
 
31 
Total Liabilities
 
 
7,021 
 
 
17 
 
 
- 
 
 
7,038 
 
 
(1,159)
 
 
5,879 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
(5,364)
 
$
25 
 
$
- 
 
$
(5,339)
 
$
- 
 
$
(5,339)

 
201
 


SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
(in thousands)
Current Risk Management Assets
 
$
1,444 
 
$
15 
 
$
- 
 
$
1,459 
 
$
(1,057)
 
$
402 
Long-term Risk Management Assets
 
 
21 
 
 
- 
 
 
- 
 
 
21 
 
 
- 
 
 
21 
Total Assets
 
 
1,465 
 
 
15 
 
 
- 
 
 
1,480 
 
 
(1,057)
 
 
423 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
1,339 
 
 
14 
 
 
- 
 
 
1,353 
 
 
(1,057)
 
 
296 
Long-term Risk Management Liabilities
 
 
- 
 
 
8 
 
 
- 
 
 
8 
 
 
(8)
 
 
- 
Total Liabilities
 
 
1,339 
 
 
22 
 
 
- 
 
 
1,361 
 
 
(1,065)
 
 
296 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
126 
 
$
(7)
 
$
- 
 
$
119 
 
$
8 
 
$
127 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
(in thousands)
Current Risk Management Assets
 
$
2,804 
 
$
41 
 
$
- 
 
$
2,845 
 
$
(2,150)
 
$
695 
Long-term Risk Management Assets
 
 
- 
 
 
- 
 
 
- 
 
 
- 
 
 
- 
 
 
- 
Total Assets
 
 
2,804 
 
 
41 
 
 
- 
 
 
2,845 
 
 
(2,150)
 
 
695 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
3,261 
 
 
17 
 
 
- 
 
 
3,278 
 
 
(2,150)
 
 
1,128 
Long-term Risk Management Liabilities
 
 
- 
 
 
- 
 
 
- 
 
 
- 
 
 
- 
 
 
- 
Total Liabilities
 
 
3,261 
 
 
17 
 
 
- 
 
 
3,278 
 
 
(2,150)
 
 
1,128 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
(457)
 
$
24 
 
$
- 
 
$
(433)
 
$
- 
 
$
(433)

(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."
(c)
There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.

 
202
 

The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and nine months ended September 30, 2013 and 2012:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 2013
 
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
(in thousands)
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
$
 746 
 
$
 1,742 
 
$
 66 
 
$
 25 
 
$
 51 
Sales to AEP Affiliates
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Regulatory Assets (a)
 
 
 - 
 
 
 (1,349)
 
 
 - 
 
 
 960 
 
 
 421 
Regulatory Liabilities (a)
 
 
 (950)
 
 
 (2,347)
 
 
 (1,264)
 
 
 18 
 
 
 130 
Total Gain (Loss) on Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
$
 (204)
 
$
 (1,954)
 
$
 (1,198)
 
$
 1,003 
 
$
 602 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 Nine Months Ended September 30, 2013
 
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
$
 1,619 
 
$
 9,586 
 
$
 3,599 
 
$
 241 
 
$
 381 
Sales to AEP Affiliates
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Regulatory Assets (a)
 
 
 - 
 
 
 (1,648)
 
 
 (5,158)
 
 
 3,162 
 
 
 427 
Regulatory Liabilities (a)
 
 
 (1,160)
 
 
 (9,209)
 
 
 1,557 
 
 
 18 
 
 
 157 
Total Gain (Loss) on Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
$
 459 
 
$
 (1,271)
 
$
 (2)
 
$
 3,421 
 
$
 965 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
203
 
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)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

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, 2013 and 2012, the Registrant Subsidiaries did not designate any fair value hedging strategies.

Accounting for Cash Flow Hedging Strategies

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

 
204
 
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, 2013 and 2012, 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, 2013 and 2012, 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, 2013, I&M designated interest rate derivatives as cash flow hedges.  During the three and nine months ended September 30, 2012, I&M and SWEPCo 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 designated as the hedged items in qualifying foreign currency hedging relationships.  During the three and nine months ended September 30, 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges.  During the three and nine months ended September 30, 2012, SWEPCo designated foreign currency derivatives as cash flow hedges.

During the three and nine months ended September 30, 2013 and 2012, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

For 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, 2013 and 2012, see Note 2.

 
205
 

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2013 and December 31, 2012 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
September 30, 2013
 
 
 
 
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
 
$
 307 
 
$
 - 
 
$
 430 
 
$
 - 
 
$
 (34)
 
$
 2,836 
I&M
 
 
 199 
 
 
 - 
 
 
 278 
 
 
 - 
 
 
 (19)
 
 
 (16,386)
OPCo
 
 
 418 
 
 
 - 
 
 
 585 
 
 
 - 
 
 
 (47)
 
 
 7,076 
PSO
 
 
 10 
 
 
 - 
 
 
 16 
 
 
 - 
 
 
 (3)
 
 
 5,891 
SWEPCo
 
 
 12 
 
 
 - 
 
 
 19 
 
 
 - 
 
 
 (3)
 
 
 (13,871)

 
 
 
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
 
$
 (172)
 
$
 (930)
 
 
 15 
I&M
 
 
 (113)
 
 
 (1,640)
 
 
 15 
OPCo
 
 
 (236)
 
 
 1,359 
 
 
 15 
PSO
 
 
 1 
 
 
 759 
 
 
 15 
SWEPCo
 
 
 1 
 
 
 (2,267)
 
 
 15 

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 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
 
$
 302 
 
$
 - 
 
$
 1,355 
 
$
 - 
 
$
 (644)
 
$
 2,077 
I&M
 
 
 200 
 
 
 - 
 
 
 931 
 
 
 19,524 
 
 
 (446)
 
 
 (19,647)
OPCo
 
 
 416 
 
 
 - 
 
 
 1,903 
 
 
 - 
 
 
 (912)
 
 
 8,095 
PSO
 
 
 25 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 21 
 
 
 6,460 
SWEPCo
 
 
 24 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 22 
 
 
 (15,571)

 
 
 
Expected to be Reclassified to
  
 
 
 
Net Income During the Next
 
 
 
 
Twelve Months
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
and Foreign
 
Company
 
Commodity
 
Currency
 
 
 
 
(in thousands)
 
APCo
 
$
 (507)
 
$
 (1,013)
I&M
 
 
 (355)
 
 
 (1,600)
OPCo
 
 
 (720)
 
 
 1,359 
PSO
 
 
 21 
 
 
 759 
SWEPCo
 
 
 22 
 
 
 (2,267)

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

 
206
 
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.

When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements 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’ 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, 2013 and December 31, 2012:

 
 
 
September 30, 2013
 
 
 
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
 
$
 850 
 
$
 6,183 
 
$
 5,812 
I&M
 
 
 560 
 
 
 4,069 
 
 
 3,824 
OPCo
 
 
 1,167 
 
 
 8,484 
 
 
 7,975 
PSO
 
 
 - 
 
 
 255 
 
 
 200 
SWEPCo
 
 
 - 
 
 
 315 
 
 
 247 

 
 
 
December 31, 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
 
$
 2,159 
 
$
 3,699 
 
$
 3,510 
I&M
 
 
 1,483 
 
 
 2,540 
 
 
 2,411 
OPCo
 
 
 3,034 
 
 
 5,198 
 
 
 4,933 
PSO
 
 
 - 
 
 
 1,509 
 
 
 1,429 
SWEPCo
 
 
 - 
 
 
 1,778 
 
 
 1,683 

 
207
 
In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts.  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, 2013 and December 31, 2012:

 
 
 
September 30, 2013
 
 
 
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
 
$
 27,044 
 
$
 - 
 
$
 22,162 
I&M
 
 
 17,796 
 
 
 - 
 
 
 14,583 
OPCo
 
 
 37,110 
 
 
 - 
 
 
 30,410 
PSO
 
 
 5 
 
 
 - 
 
 
 5 
SWEPCo
 
 
 6 
 
 
 - 
 
 
 6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 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
 
$
 49,465 
 
$
 1,822 
 
$
 30,160 
I&M
 
 
 53,499 
 
 
 1,252 
 
 
 40,240 
OPCo
 
 
 69,516 
 
 
 2,561 
 
 
 42,386 
PSO
 
 
 - 
 
 
 - 
 
 
 - 
SWEPCo
 
 
 - 
 
 
 - 
 
 
 - 

9.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

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

 
208
 
For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which are nonbinding 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.  Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs.  Some of these inputs may be internally developed or extrapolated and utilized 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, 2013 and December 31, 2012 are summarized in the following table:

 
 
September 30, 2013
 
December 31, 2012
Company
 
Book Value
 
Fair Value
 
Book Value
 
Fair Value
 
 
(in thousands)
APCo
 
$
 3,427,917 
 
$
 3,957,321 
 
$
 3,702,442 
 
$
 4,555,143 
I&M
 
 
 2,271,613 
 
 
 2,461,671 
 
 
 2,057,666 
 
 
 2,372,017 
OPCo
 
 
 3,698,574 
 
 
 4,071,613 
 
 
 3,860,440 
 
 
 4,560,337 
PSO
 
 
 949,826 
 
 
 1,090,934 
 
 
 949,871 
 
 
 1,175,759 
SWEPCo
 
 
 2,043,244 
 
 
 2,254,078 
 
 
 2,046,228 
 
 
 2,400,509 

 
209
 
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 fixed income 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 fixed income investments held in these trusts and generally intends to sell fixed income 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, 2013 and December 31, 2012:

 
 
 
September 30, 2013
 
December 31, 2012
 
 
 
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
 
$
 14,438 
 
$
 - 
 
$
 - 
 
$
 16,783 
 
$
 - 
 
$
 - 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 
 620,944 
 
 
 34,377 
 
 
 (2,662)
 
 
 647,918 
 
 
 58,268 
 
 
 (747)
 
Corporate Debt
 
 
 38,272 
 
 
 2,684 
 
 
 (1,786)
 
 
 35,399 
 
 
 4,903 
 
 
 (1,352)
 
State and Local Government
 
 
 244,172 
 
 
 851 
 
 
 (358)
 
 
 270,090 
 
 
 1,006 
 
 
 (863)
 
  Subtotal Fixed Income Securities
 
 903,388 
 
 
 37,912 
 
 
 (4,806)
 
 
 953,407 
 
 
 64,177 
 
 
 (2,962)
Equity Securities - Domestic
 
 
 921,292 
 
 
 414,931 
 
 
 (81,125)
 
 
 735,582 
 
 
 284,599 
 
 
 (76,557)
Spent Nuclear Fuel and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning Trusts
 
$
 1,839,118 
 
$
 452,843 
 
$
 (85,931)
 
$
 1,705,772 
 
$
 348,776 
 
$
 (79,519)

 
210
 
The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2013 and 2012:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013 
 
2012 
 
2013 
 
2012 
 
(in thousands)
Proceeds from Investment Sales
$
 249,314 
 
$
 181,988 
 
$
 635,256 
 
$
 698,567 
Purchases of Investments
 
 263,958 
 
 
 199,150 
 
 
 675,727 
 
 
 744,131 
Gross Realized Gains on Investment Sales
 
 4,113 
 
 
 2,046 
 
 
 16,011 
 
 
 6,978 
Gross Realized Losses on Investment Sales
 
 2,147 
 
 
 924 
 
 
 11,859 
 
 
 3,143 

The adjusted cost of fixed income securities was $866 million and $889 million as of September 30, 2013 and December 31, 2012, respectively.  The adjusted cost of equity securities was $506 million and $451 million as of September 30, 2013 and December 31, 2012, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2013 was as follows:

 
Fair Value of
 
Fixed Income
 
Securities
 
(in thousands)
Within 1 year
$
 73,908 
1 year – 5 years
 
 378,271 
5 years – 10 years
 
 210,201 
After 10 years
 
 241,008 
Total
$
 903,388 

 
211
 
Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 and December 31, 2012.  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.

APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 1,799 
 
$
 85,442 
 
$
 13,701 
 
$
 (55,860)
 
$
 45,082 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 452 
 
 
 - 
 
 
 (145)
 
 
 307 
Total Risk Management Assets
$
 1,799 
 
$
 85,894 
 
$
 13,701 
 
$
 (56,005)
 
$
 45,389 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 1,274 
 
$
 80,580 
 
$
 2,790 
 
$
 (61,352)
 
$
 23,292 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 575 
 
 
 - 
 
 
 (145)
 
 
 430 
Total Risk Management Liabilities
$
 1,274 
 
$
 81,155 
 
$
 2,790 
 
$
 (61,497)
 
$
 23,722 

APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 4,161 
 
$
 166,916 
 
$
 17,058 
 
$
 (123,117)
 
$
 65,018 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 498 
 
 
 - 
 
 
 (196)
 
 
 302 
Total Risk Management Assets
$
 4,161 
 
$
 167,414 
 
$
 17,058 
 
$
 (123,313)
 
$
 65,320 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 1,959 
 
$
 158,665 
 
$
 6,079 
 
$
 (132,884)
 
$
 33,819 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,551 
 
 
 - 
 
 
 (196)
 
 
 1,355 
Total Risk Management Liabilities
$
 1,959 
 
$
 160,216 
 
$
 6,079 
 
$
 (133,080)
 
$
 35,174 

 
212
 


I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 1,184 
 
$
 56,155 
 
$
 9,015 
 
$
 (36,670)
 
$
 29,684 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 294 
 
 
 - 
 
 
 (95)
 
 
 199 
Total Risk Management Assets
 
 1,184 
 
 
 56,449 
 
 
 9,015 
 
 
 (36,765)
 
 
 29,883 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (c)
 
 5,684 
 
 
 - 
 
 
 - 
 
 
 8,754 
 
 
 14,438 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 - 
 
 
 620,944 
 
 
 - 
 
 
 - 
 
 
 620,944 
 
Corporate Debt
 
 - 
 
 
 38,272 
 
 
 - 
 
 
 - 
 
 
 38,272 
 
State and Local Government
 
 - 
 
 
 244,172 
 
 
 - 
 
 
 - 
 
 
 244,172 
 
 
Subtotal Fixed Income Securities
 
 - 
 
 
 903,388 
 
 
 - 
 
 
 - 
 
 
 903,388 
Equity Securities - Domestic (d)
 
 921,292 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 921,292 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 926,976 
 
 
 903,388 
 
 
 - 
 
 
 8,754 
 
 
 1,839,118 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 928,160 
 
$
 959,837 
 
$
 9,015 
 
$
 (28,011)
 
$
 1,869,001 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 838 
 
$
 54,905 
 
$
 1,836 
 
$
 (40,282)
 
$
 17,297 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 373 
 
 
 - 
 
 
 (95)
 
 
 278 
Total Risk Management Liabilities
$
 838 
 
$
 55,278 
 
$
 1,836 
 
$
 (40,377)
 
$
 17,575 

 
213
 


I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
 
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 2,858 
 
$
 120,242 
 
$
 11,717 
 
$
 (84,474)
 
$
 50,343 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 330 
 
 
 - 
 
 
 (130)
 
 
 200 
Total Risk Management Assets
 
 2,858 
 
 
 120,572 
 
 
 11,717 
 
 
 (84,604)
 
 
 50,543 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (c)
 
 6,508 
 
 
 - 
 
 
 - 
 
 
 10,275 
 
 
 16,783 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 - 
 
 
 647,918 
 
 
 - 
 
 
 - 
 
 
 647,918 
 
Corporate Debt
 
 - 
 
 
 35,399 
 
 
 - 
 
 
 - 
 
 
 35,399 
 
State and Local Government
 
 - 
 
 
 270,090 
 
 
 - 
 
 
 - 
 
 
 270,090 
 
 
Subtotal Fixed Income Securities
 
 - 
 
 
 953,407 
 
 
 - 
 
 
 - 
 
 
 953,407 
Equity Securities - Domestic (d)
 
 735,582 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 735,582 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 742,090 
 
 
 953,407 
 
 
 - 
 
 
 10,275 
 
 
 1,705,772 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 744,948 
 
$
 1,073,979 
 
$
 11,717 
 
$
 (74,329)
 
$
 1,756,315 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 1,346 
 
$
 110,621 
 
$
 4,176 
 
$
 (91,183)
 
$
 24,960 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,061 
 
 
 - 
 
 
 (130)
 
 
 931 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 19,524 
 
 
 - 
 
 
 - 
 
 
 19,524 
Total Risk Management Liabilities
$
 1,346 
 
$
 131,206 
 
$
 4,176 
 
$
 (91,313)
 
$
 45,415 

 
214
 


OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Cash Deposits (e)
$
 8,022 
 
$
 26 
 
$
 - 
 
$
 17 
 
$
 8,065 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
 
 2,469 
 
 
 119,749 
 
 
 18,799 
 
 
 (78,663)
 
 
 62,354 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 616 
 
 
 - 
 
 
 (198)
 
 
 418 
Total Risk Management Assets
 
 2,469 
 
 
 120,365 
 
 
 18,799 
 
 
 (78,861)
 
 
 62,772 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 10,491 
 
$
 120,391 
 
$
 18,799 
 
$
 (78,844)
 
$
 70,837 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 1,748 
 
$
 113,044 
 
$
 3,828 
 
$
 (86,197)
 
$
 32,423 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 783 
 
 
 - 
 
 
 (198)
 
 
 585 
Total Risk Management Liabilities
$
 1,748 
 
$
 113,827 
 
$
 3,828 
 
$
 (86,395)
 
$
 33,008 

OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Cash Deposits (e)
$
 - 
 
$
 26 
 
$
 - 
 
$
 39 
 
$
 65 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
 
 5,848 
 
 
 238,254 
 
 
 23,973 
 
 
 (175,890)
 
 
 92,185 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 688 
 
 
 - 
 
 
 (272)
 
 
 416 
Total Risk Management Assets
 
 5,848 
 
 
 238,942 
 
 
 23,973 
 
 
 (176,162)
 
 
 92,601 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 5,848 
 
$
 238,968 
 
$
 23,973 
 
$
 (176,123)
 
$
 92,666 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 2,753 
 
$
 226,536 
 
$
 8,544 
 
$
 (189,616)
 
$
 48,217 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,175 
 
 
 - 
 
 
 (272)
 
 
 1,903 
Total Risk Management Liabilities
$
 2,753 
 
$
 228,711 
 
$
 8,544 
 
$
 (189,888)
 
$
 50,120 

 
215
 


PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 1,543 
 
$
 - 
 
$
 (552)
 
$
 991 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 10 
 
 
 - 
 
 
 - 
 
 
 10 
Total Risk Management Assets
$
 - 
 
$
 1,553 
 
$
 - 
 
$
 (552)
 
$
 1,001 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 1,931 
 
$
 - 
 
$
 (559)
 
$
 1,372 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 16 
 
 
 - 
 
 
 - 
 
 
 16 
Total Risk Management Liabilities
$
 - 
 
$
 1,947 
 
$
 - 
 
$
 (559)
 
$
 1,388 

PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 1,657 
 
$
 - 
 
$
 (1,142)
 
$
 515 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 42 
 
 
 - 
 
 
 (17)
 
 
 25 
Total Risk Management Assets
$
 - 
 
$
 1,699 
 
$
 - 
 
$
 (1,159)
 
$
 540 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 7,021 
 
$
 - 
 
$
 (1,142)
 
$
 5,879 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 17 
 
 
 - 
 
 
 (17)
 
 
 - 
Total Risk Management Liabilities
$
 - 
 
$
 7,038 
 
$
 - 
 
$
 (1,159)
 
$
 5,879 

 
216
 


SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (e)
$
 14,186 
 
$
 - 
 
$
 - 
 
$
 3,465 
 
$
 17,651 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
 
 - 
 
 
 1,464 
 
 
 - 
 
 
 (1,053)
 
 
 411 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 12 
 
 
 - 
 
 
 - 
 
 
 12 
Total Risk Management Assets
 
 - 
 
 
 1,476 
 
 
 - 
 
 
 (1,053)
 
 
 423 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 14,186 
 
$
 1,476 
 
$
 - 
 
$
 2,412 
 
$
 18,074 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 1,338 
 
$
 - 
 
$
 (1,061)
 
$
 277 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 19 
 
 
 - 
 
 
 - 
 
 
 19 
Total Risk Management Liabilities
$
 - 
 
$
 1,357 
 
$
 - 
 
$
 (1,061)
 
$
 296 

SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 2,804 
 
$
 - 
 
$
 (2,133)
 
$
 671 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 41 
 
 
 - 
 
 
 (17)
 
 
 24 
Total Risk Management Assets
$
 - 
 
$
 2,845 
 
$
 - 
 
$
 (2,150)
 
$
 695 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 3,261 
 
$
 - 
 
$
 (2,133)
 
$
 1,128 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 17 
 
 
 - 
 
 
 (17)
 
 
 - 
Total Risk Management Liabilities
$
 - 
 
$
 3,278 
 
$
 - 
 
$
 (2,150)
 
$
 1,128 

(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)
Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
(c)
Amounts in “Other” column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(d)
Amounts represent publicly traded equity securities and equity-based mutual funds.
(e)
Amounts in “Other” column primarily represent cash deposits with third parties.  Level 1 and Level 2 amounts primarily represent investments in money market funds.
 
There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2013 and 2012.
 
217
 
 
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, 2013
 
APCo
 
I&M
 
OPCo
 
 
(in thousands)
Balance as of June 30, 2013
 
$
 12,976 
 
$
 8,967 
 
$
 18,347 
Realized Gain (Loss) Included in Net Income
 
 
 
 
 
 
 
 
 
 
(or Changes in Net Assets) (a) (b)
 
 
 (1,200)
 
 
 (754)
 
 
 (1,616)
Unrealized Gain (Loss) Included in Net
 
 
 
 
 
 
 
 
 
 
Income (or Changes in Net Assets) Relating
 
 
 
 
 
 
 
 
 
 
to Assets Still Held at the Reporting Date (a)
 
 
 - 
 
 
 - 
 
 
 (89)
Realized and Unrealized Gains (Losses)
 
 
 
 
 
 
 
 
 
 
Included in Other Comprehensive Income
 
 
 - 
 
 
 - 
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 (1,058)
 
 
 (757)
 
 
 (1,504)
Transfers into Level 3 (d) (e)
 
 
 13 
 
 
 9 
 
 
 18 
Transfers out of Level 3 (e) (f)
 
 
 (15)
 
 
 (11)
 
 
 (21)
Changes in Fair Value Allocated to Regulated
 
 
 
 
 
 
 
 
 
 
Jurisdictions (g)
 
 
 195 
 
 
 (275)
 
 
 (164)
Balance as of September 30, 2013
 
$
 10,911 
 
$
 7,179 
 
$
 14,971 

Three Months Ended September 30, 2012
 
APCo
 
I&M
 
OPCo
 
 
(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) (e)
 
 
 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 

Nine Months Ended September 30, 2013
 
APCo
 
I&M
 
OPCo
 
 
(in thousands)
Balance as of December 31, 2012
 
$
 10,979 
 
$
 7,541 
 
$
 15,429 
Realized Gain (Loss) Included in Net Income
 
 
 
 
 
 
 
 
 
 
(or Changes in Net Assets) (a) (b)
 
 
 (3,450)
 
 
 (2,386)
 
 
 (4,879)
Unrealized Gain (Loss) Included in Net
 
 
 
 
 
 
 
 
 
 
Income (or Changes in Net Assets) Relating
 
 
 
 
 
 
 
 
 
 
to Assets Still Held at the Reporting Date (a)
 
 
 - 
 
 
 - 
 
 
 351 
Realized and Unrealized Gains (Losses)
 
 
 
 
 
 
 
 
 
 
Included in Other Comprehensive Income
 
 
 - 
 
 
 - 
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 1,712 
 
 
 1,213 
 
 
 2,463 
Transfers into Level 3 (d) (e)
 
 
 961 
 
 
 661 
 
 
 1,353 
Transfers out of Level 3 (e) (f)
 
 
 (925)
 
 
 (637)
 
 
 (1,303)
Changes in Fair Value Allocated to Regulated
 
 
 
 
 
 
 
 
 
 
Jurisdictions (g)
 
 
 1,634 
 
 
 787 
 
 
 1,557 
Balance as of September 30, 2013
 
$
 10,911 
 
$
 7,179 
 
$
 14,971 

 
218
 
Nine Months Ended September 30, 2012
 
APCo
 
I&M
 
OPCo
 
 
(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) (e)
 
 
 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 

 
(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)
Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
 
(f)
Represents existing assets or liabilities that were previously categorized as Level 3.
 
(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 liabilities/assets.

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of September 30, 2013:

APCo
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
  
Forward Price Range
 
Assets
 
Liabilities
Technique
Unobservable Input (a)
  
Low
 
High
 
 
(in thousands)
 
 
 
 
  
 
 
 
 
 
Energy Contracts
 
$
 11,506 
 
$
 1,940 
 
Discounted Cash Flow 
 
Forward Market Price 
  
$
 12.52 
 
$
 55.40 
FTRs
 
 
 2,195 
 
 
 850 
 
Discounted Cash Flow 
 
Forward Market Price 
  
 
 (5.26)
 
 
 10.85 
Total
 
$
 13,701 
 
$
 2,790 
 
 
 
 
  
 
 
 
 
 

I&M
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
  
Forward Price Range
 
Assets
 
Liabilities
Technique
Unobservable Input (a)
  
Low
 
High
 
 
(in thousands)
 
 
 
 
  
 
 
 
 
 
Energy Contracts
 
$
 7,571 
 
$
 1,276 
 
Discounted Cash Flow 
 
Forward Market Price 
  
$
 12.52 
 
$
 55.40 
FTRs
 
 
 1,444 
 
 
 560 
 
Discounted Cash Flow 
 
Forward Market Price 
  
 
 (5.26)
 
 
 10.85 
Total
 
$
 9,015 
 
$
 1,836 
 
 
 
 
  
 
 
 
 
 

OPCo
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
  
Forward Price Range
 
Assets
 
Liabilities
Technique
Unobservable Input (a)
  
Low
 
High
 
 
(in thousands)
 
 
 
 
  
 
 
 
 
 
Energy Contracts
 
$
 15,787 
 
$
 2,661 
 
Discounted Cash Flow 
 
Forward Market Price 
  
$
 12.52 
 
$
 55.40 
FTRs
 
 
 3,012 
 
 
 1,167 
 
Discounted Cash Flow 
 
Forward Market Price 
  
 
 (5.26)
 
 
 10.85 
Total
 
$
 18,799 
 
$
 3,828 
 
 
 
 
  
 
 
 
 
 

 
(a)
Represents market prices in dollars per MWh.

 
219
 
10.  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 IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013.  The completion of the federal audit did not result in a material impact on net income, cash flow or financial condition.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions.  Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.

The Registrant Subsidiaries file income tax returns in various state and local jurisdictions.  These taxing authorities routinely examine the 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.  The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2008.

Federal Tax Regulations

In the third quarter of 2013, the U.S. Treasury Department issued final regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014.  The U.S. Treasury Department had previously issued guidance in the form of proposed and temporary regulations which was generally effective for tax years beginning in 2012, which was moved to tax years beginning in 2014 in November, 2012.  In addition, the IRS has issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry.  The impact of these final regulations is not material to net income or financial condition, except for an approximate $10 million reduction to I&M’s cash flows in 2014.

State Tax Legislation

In the third quarter of 2013, 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% to 6.5% in 2014.  The enacted provisions will not materially impact net income, cash flows or financial condition.

 
220
 
11.  FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2013 are shown in the tables below:

 
 
 
 
Principal
 
Interest
 
 
Company
 
Type of Debt
 
Amount (a)
 
Rate
 
Due Date
Issuances:
 
 
 
(in thousands)
 
(%)
 
 
APCo
 
Pollution Control Bonds
 
$
 30,000 
 
3.25 
 
2018 
APCo
 
Pollution Control Bonds
 
 
 40,000 
 
3.25 
 
2018 
I&M
 
Notes Payable
 
 
 101,354 
 
Variable
 
2017 
I&M
 
Senior Unsecured Notes
 
 
 250,000 
 
3.20 
 
2023 
OPCo
 
Other Long-term Debt
 
 
 200,000 
(b)
Variable
 
2015 
OPCo
 
Other Long-term Debt
 
 
 600,000 
(c)
Variable
 
2015 
OPCo
 
Pollution Control Bonds
 
 
 50,000 
 
Variable
 
2014 
OPCo
 
Pollution Control Bonds
 
 
 65,000 
 
Variable
 
2014 
OPCo
 
Securitization Bonds
 
 
 164,900 
 
0.96 
 
2018 
OPCo
 
Securitization Bonds
 
 
 102,508 
 
2.05 
 
2020 

 
 
 
 
 
Principal
 
Interest
 
 
Company
 
Type of Debt
 
Amount Paid
 
Rate
 
Due Date
Retirements and
 
 
 
(in thousands)
 
(%)
 
 
 
Principal Payments:
 
 
 
 
 
 
 
 
 
APCo
 
Land Note
 
$
 21 
 
13.718 
 
2026 
APCo
 
Pollution Control Bonds
 
 
 30,000 
 
4.85 
 
2013 
APCo
 
Pollution Control Bonds
 
 
 40,000 
 
4.85 
 
2013 
APCo
 
Senior Unsecured Notes
 
 
 275,000 
 
Variable
 
2013 
I&M
 
Notes Payable
 
 
 6,083 
 
5.44 
 
2013 
I&M
 
Notes Payable
 
 
 9,811 
 
4.00 
 
2014 
I&M
 
Notes Payable
 
 
 12,071 
 
Variable
 
2015 
I&M
 
Notes Payable
 
 
 14,945 
 
Variable
 
2016 
I&M
 
Notes Payable
 
 
 10,350 
 
2.12 
 
2016 
I&M
 
Notes Payable
 
 
 31,289 
 
Variable
 
2016 
I&M
 
Notes Payable
 
 
 8,204 
 
Variable
 
2017 
I&M
 
Other Long-term Debt
 
 
 705 
 
6.00 
 
2025 
I&M
 
Other Long-term Debt
 
 
 4,086 
 
Variable
 
2015 
I&M
 
Pollution Control Bonds
 
 
 40,000 
 
5.25 
 
2025 
OPCo
 
Other Long-term Debt
 
 
 200,000 
(b)
Variable
 
2015 
OPCo
 
Pollution Control Bonds
 
 
 56,000 
 
5.10 
 
2013 
OPCo
 
Pollution Control Bonds
 
 
 50,000 
 
5.15 
 
2026 
OPCo
 
Pollution Control Bonds
 
 
 65,000 
 
4.90 
 
2037 
OPCo
 
Senior Unsecured Notes
 
 
 250,000 
 
5.50 
 
2013 
OPCo
 
Senior Unsecured Notes
 
 
 250,000 
 
5.50 
 
2013 
OPCo
 
Senior Unsecured Notes
 
 
 250,000 
 
5.75 
 
2013 
OPCo
 
Senior Unsecured Notes
 
 
 225,000 
 
6.38 
 
2033 
PSO
 
Notes Payable
 
 
 301 
 
3.00 
 
2027 
SWEPCo
 
Notes Payable
 
 
 3,250 
 
4.58 
 
2032 

 
(a)
Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
 
(b)
Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013.
 
(c)
Draw on a $1 billion term credit facility due in May 2015.

 
221
 

In February 2013, AEP entered into a $1 billion credit facility due in May 2015.  In July 2013, the $1 billion term credit facility due in May 2015 was terminated.  Also in July 2013, AEPGenCo, APCo, KPCo and OPCo entered into a $1 billion term credit facility due in May 2015 to provide liquidity during the corporate separation process.  Upon entering into the new term credit facility, OPCo repaid the $200 million Long-term Debt – Affiliated and subsequently borrowed $600 million Long-term Debt – Nonaffiliated under the new term credit facility.  Under the credit facility, OPCo may assign borrowings to AEPGenCo upon the transfer of OPCo’s generation assets to AEPGenCo.  Subject to regulatory approval, AEPGenCo may further assign a portion of the borrowings to APCo and KPCo, not to exceed $500 million and $250 million, respectively, upon AEPGenCo’s subsequent transfer of certain of those generation assets to APCo and KPCo.

In October 2013, I&M retired $37 million of Notes Payable related to DCC Fuel.

As of September 30, 2013, trustees held on behalf of I&M and OPCo, $40 million and $460 million, respectively, of their reacquired Pollution Control Bonds.

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.  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%.

 
222
 
Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds a majority of AEP’s nonutility subsidiaries.  The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC.  The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2013 and December 31, 2012 are included in Advances to Affiliates and Advances from Affiliates, respectively, 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, 2013 are described in the following table:

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loans to
 
 
 
 
 
Maximum
 
Maximum
 
Average
 
Average
 
(Borrowings from)
 
Authorized
 
 
Borrowings
 
Loans
 
Borrowings
 
Loans
 
the Utility
 
Short-term
 
 
from the Utility
 
to the Utility
 
from the Utility
 
to the Utility
 
Money Pool as of
 
Borrowing
Company
 
Money Pool
 
Money Pool
 
Money Pool
 
Money Pool
 
September 30, 2013
 
Limit
 
 
(in thousands)
APCo
 
$
 331,771 
 
$
 39,372 
 
$
 126,391 
 
$
 23,632 
 
$
 (253,352)
 
$
 600,000 
I&M
 
 
 23,135 
 
 
 384,435 
 
 
 8,308 
 
 
 239,647 
 
 
 322,476 
 
 
 500,000 
OPCo
 
 
 410,456 
 
 
 415,605 
 
 
 228,719 
 
 
 59,047 
 
 
 9,401 
 
 
 600,000 
PSO
 
 
 46,806 
 
 
 52,734 
 
 
 18,658 
 
 
 18,808 
 
 
 19,442 
 
 
 300,000 
SWEPCo
 
 
 15,386 
 
 
 153,830 
 
 
 4,154 
 
 
 38,449 
 
 
 18,634 
 
 
 350,000 

The activity in the above table does not include short-term lending activity of OPCo’s wholly-owned subsidiary, AEPGenCo, which is a participant in the Nonutility Money Pool.  The amounts of outstanding borrowings from the Nonutility Money Pool as of September 30, 2013 is included in Advances from Affiliates on OPCo’s condensed balance sheet.  For the nine months ended September 30, 2013, AEPGenCo had the following activity in the Nonutility Money Pool:

 
 
 
 
 
 
 
 
 
 
 
 
Maximum
 
Maximum
 
Average
 
Average
 
Borrowings
 
Borrowings
 
Loans
 
Borrowings
 
Loans
 
from the Nonutility
 
from the Nonutility
 
to the Nonutility
 
from the Nonutility
 
to the Nonutility
 
Money Pool as of
 
Money Pool
 
Money Pool
 
Money Pool
 
Money Pool
 
September 30, 2013
 
(in thousands)
$
 1,047 
 
$
 1,027 
 
$
 201 
 
$
 208 
 
$
 338 
 

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,
 
 
2013 
 
2012 
Maximum Interest Rate
 
 0.43 
%
 
 0.56 
%
Minimum Interest Rate
 
 0.28 
%
 
 0.44 
%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2013 and 2012 are summarized for all Registrant Subsidiaries in the following table:

 
 
Average Interest Rate
 
Average Interest Rate
 
 
for Funds Borrowed
 
 for Funds Loaned
 
 
from the Utility Money Pool for
 
 to the Utility Money Pool for
 
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
Company
 
2013 
 
2012 
2013 
 
2012 
APCo
 
 0.33 
%
 
 0.48 
%
 
 0.34 
%
 
 0.48 
%
I&M
 
 0.36 
%
 
 - 
%
 
 0.33 
%
 
 0.47 
%
OPCo
 
 0.34 
%
 
 0.47 
%
 
 0.32 
%
 
 0.50 
%
PSO
 
 0.34 
%
 
 - 
%
 
 0.32 
%
 
 0.47 
%
SWEPCo
 
 0.33 
%
 
 0.53 
%
 
 0.36 
%
 
 0.47 
%

 
223
 
AEPGenCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to the Nonutility Money Pool for the nine months ended September 30, 2013 are summarized in the following table:

 
 
Maximum
 
Minimum
 
Maximum
 
Minimum
 
Average
 
Average
 
 
Interest Rate
 
Interest Rate
 
Interest Rate
 
Interest Rate
 
Interest Rate
 
Interest Rate
 
 
for Funds
 
for Funds
 
for Funds
 
for Funds
 
for Funds
 
for Funds
Nine Months
 
Borrowed from
 
Borrowed from
 
Loaned to
 
Loaned to
 
Borrowed from
 
Loaned to
Ended
 
the Nonutility
 
the Nonutility
 
the Nonutility
 
the Nonutility
 
the Nonutility
 
the Nonutility
September 30,
 
Money Pool
 
Money Pool
Money Pool
 
Money Pool
 
Money Pool
 
Money Pool
2013 
 
 0.61 
%
 
 0.53 
%
 
 0.35 
%
 
 0.32 
%
 
 0.56 
%
 
 0.34 
%

Short-term Debt

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

 
 
 
 
 
September 30, 2013
 
December 31, 2012
 
 
 
 
 
Outstanding
 
Interest
 
Outstanding
 
Interest
Company
 
Type of Debt
Amount
Rate (a)
 
Amount
Rate (a)
 
 
 
 
 
(in thousands)
 
 
 
 
(in thousands)
 
 
 
SWEPCo
 
Line of Credit – Sabine
 
$
 - 
 
 - 
%
 
$
 2,603 
 
 1.82 
%

      (a)  Weighted average rate.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 4.

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 2013, AEP Credit amended its receivables securitization agreement.  The agreement provides a commitment of $700 million from bank conduits to purchase receivables.  AEP Credit amended a commitment of $385 million to now expire in June 2014.  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, 2013 and December 31, 2012 was as follows:

 
 
 
September 30,
 
December 31,
Company
 
2013 
 
2012 
 
 
 
(in thousands)
APCo
 
$
 135,579 
 
$
 153,719 
I&M
 
 
 143,804 
 
 
 123,447 
OPCo
 
 
 321,054 
 
 
 300,675 
PSO
 
 
 147,586 
 
 
 85,530 
SWEPCo
 
 
 180,922 
 
 
 132,449 

 
224
 
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
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
(in thousands)
APCo
 
$
 1,575 
 
$
 1,703 
 
$
 4,590 
 
$
 5,389 
I&M
 
 
 1,762 
 
 
 1,674 
 
 
 4,744 
 
 
 4,738 
OPCo
 
 
 5,076 
 
 
 5,362 
 
 
 14,440 
 
 
 15,900 
PSO
 
 
 1,549 
 
 
 1,990 
 
 
 4,314 
 
 
 5,547 
SWEPCo
 
 
 1,649 
 
 
 1,786 
 
 
 4,413 
 
 
 4,720 

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

 
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Company
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
(in thousands)
APCo
 
$
 340,438 
 
$
 351,570 
 
$
 1,081,615 
 
$
 993,975 
I&M
 
 
 384,316 
 
 
 358,936 
 
 
 1,097,563 
 
 
 1,018,933 
OPCo
 
 
 658,829 
 
 
 790,115 
 
 
 2,017,746 
 
 
 2,284,749 
PSO
 
 
 382,167 
 
 
 342,819 
 
 
 944,062 
 
 
 919,343 
SWEPCo
 
 
 450,294 
 
 
 444,461 
 
 
 1,171,306 
 
 
 1,145,182 

12.  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.  OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding.  SWEPCo holds a significant variable interest in DHLC.  Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC.  I&M and OPCo each hold a significant variable interest in AEGCo.
 
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, 2013 and 2012 were $41 million and $35 million, respectively, and for the nine months ended September 30, 2013 and 2012 were $125 million and $126 million, respectively.  See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets.

 
225
 
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, 2013 and December 31, 2012
(in thousands)
 
 
Sabine
ASSETS
 
2013 
 
2012 
Current Assets
 
$
 64,737 
 
$
 56,535 
Net Property, Plant and Equipment
 
 
 160,575 
 
 
 170,436 
Other Noncurrent Assets
 
 
 55,760 
 
 
 55,076 
Total Assets
 
$
 281,072 
 
$
 282,047 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
Current Liabilities
 
$
 32,005 
 
$
 31,446 
Noncurrent Liabilities
 
 
 248,745 
 
 
 250,340 
Equity
 
 
 322 
 
 
 261 
Total Liabilities and Equity
 
$
 281,072 
 
$
 282,047 

I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI 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, 2013 and 2012 were $32 million and $23 million, respectively, and for the nine months ended September 30, 2013 and 2012 were $96 million and $82 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.  In October 2013, the lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC.  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, 2013 and December 31, 2012
(in thousands)
 
 
DCC Fuel
ASSETS
 
2013 
 
2012 
Current Assets
 
$
 155,448 
 
$
 132,886 
Net Property, Plant and Equipment
 
 
 180,541 
 
 
 176,065 
Other Noncurrent Assets
 
 
 78,689 
 
 
 92,473 
Total Assets
 
$
 414,678 
 
$
 401,424 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
Current Liabilities
 
$
 138,796 
 
$
 120,873 
Noncurrent Liabilities
 
 
 275,882 
 
 
 280,551 
Total Liabilities and Equity
 
$
 414,678 
 
$
 401,424 

Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property.  Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant.  Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding.  The securitized bonds totaled $267 million as of September 30, 2013, and are included in current and long-term debt on the condensed balance sheet.  Ohio Phase-in-Recovery Funding has securitized assets of $137 million as of September 30, 2013, which is presented separately on the face of the condensed balance sheet.  The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from
 
 
226
 
customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO.  In August 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to OPCo or any other AEP entity.  OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs.

The balances below represent the assets and liabilities of Ohio Phase-in-Recovery Funding that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

OHIO POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
September 30, 2013
(in thousands)
 
 
Ohio
 
 
Phase-in-
 
 
Recovery
 
 
Funding
ASSETS
 
2013 
Current Assets
 
$
 12,021 
Other Noncurrent Assets (a)
 
 
 261,005 
Total Assets
 
$
 273,026 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
Current Liabilities
 
$
 35,550 
Noncurrent Liabilities
 
 
 236,139 
Equity
 
 
 1,337 
Total Liabilities and Equity
 
$
 273,026 

 
(a) Includes an intercompany item eliminated in consolidation of $121 million.

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, 2013 and 2012 were $21 million and $20 million, respectively, and for the nine months ended September 30, 2013 and 2012 were $53 million and $54 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, 2013
 
December 31, 2012
 
 
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
 
 
 1,102 
 
 
 1,102 
 
 
 946 
 
 
 946 
SWEPCo's Guarantee of Debt
 
 
 - 
 
 
 44,897 
 
 
 - 
 
 
 49,564 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Investment in DHLC
 
$
 8,745 
 
$
 53,642 
 
$
 8,589 
 
$
 58,153 

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
 
 
227
 
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
 
2013 
 
2012 
 
2013 
 
2012 
 
 
(in thousands)
APCo
 
$
 39,779 
 
$
 47,820 
 
$
 120,315 
 
$
 130,260 
I&M
 
 
 25,988 
 
 
 31,134 
 
 
 82,192 
 
 
 88,618 
OPCo
 
 
 58,528 
 
 
 72,751 
 
 
 169,949 
 
 
 193,686 
PSO
 
 
 19,535 
 
 
 21,728 
 
 
 57,504 
 
 
 60,625 
SWEPCo
 
 
 28,431 
 
 
 33,154 
 
 
 85,506 
 
 
 93,120 

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

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30, 2013
 
December 31, 2012
 
 
As Reported on the
 
Maximum
 
As Reported on the
 
Maximum
Company
 
Balance Sheet
 
Exposure
 
Balance Sheet
 
Exposure
 
 
(in thousands)
APCo
 
$
 7,637 
 
$
 7,637 
 
$
 29,819 
 
$
 29,819 
I&M
 
 
 6,560 
 
 
 6,560 
 
 
 17,911 
 
 
 17,911 
OPCo
 
 
 14,217 
 
 
 14,217 
 
 
 39,323 
 
 
 39,323 
PSO
 
 
 4,710 
 
 
 4,710 
 
 
 13,381 
 
 
 13,381 
SWEPCo
 
 
 6,778 
 
 
 6,778 
 
 
 19,669 
 
 
 19,669 

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 “Rockport Lease” section of Note 11 in the 2012 Annual Report.

Total billings from AEGCo were as follows:

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Company
 
2013 
 
2012 
 
2013 
 
2012 
 
 
(in thousands)
I&M
 
$
 66,114 
 
$
 65,051 
 
$
 177,840 
 
$
 177,790 
OPCo
 
 
 37,255 
 
 
 46,184 
 
 
 107,876 
 
 
 149,424 

The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30, 2013
 
December 31, 2012
 
 
As Reported on
 
Maximum
 
As Reported on
 
Maximum
Company
 
the Balance Sheet
 
Exposure
 
the Balance Sheet
 
Exposure
 
 
(in thousands)
I&M
 
$
 26,323 
 
$
 26,323 
 
$
 25,498 
 
$
 25,498 
OPCo
 
 
 9,708 
 
 
 9,708 
 
 
 16,302 
 
 
 16,302 

 
228
 
13.  SUSTAINABLE COST REDUCTIONS

In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings.  Management selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate current employee benefit programs.  The process resulted in involuntary severances and was completed by the end of the first quarter of 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 Other Operation expense in 2012 primarily related to severance benefits as a result of the sustainable cost reductions initiative.  The total amount incurred in 2012 by Registrant Subsidiary was as follows:

Company
 
Total Cost Incurred
 
 
(in thousands)
APCo
 
$
 8,472 
I&M
 
 
 5,678 
OPCo
 
 
 13,498 
PSO
 
 
 3,675 
SWEPCo
 
 
 5,709 

The Registrant Subsidiaries’ sustainable cost reduction activity for the nine months ended September 30, 2013 is described in the following table:

 
 
 
 
 
Expense
 
Incurred for
 
 
 
 
 
 
 
Remaining
 
 
Balance as of
 
Allocation from
 
Registrant
 
 
 
 
 
 
Balance as of
Company
 
 December 31, 2012
 
    AEPSC
 
Subsidiaries
 
Settled
 
Adjustments
 
September 30, 2013
 
 
(in thousands)
APCo
 
$
 1,321 
 
$
 1,017 
 
$
 - 
 
$
 (1,575)
 
$
 (730)
 
$
 33 
I&M
 
 
 1,357 
 
 
 736 
 
 
 - 
 
 
 (1,681)
 
 
 (373)
 
 
 39 
OPCo
 
 
 3,450 
 
 
 1,354 
 
 
 6,114 
 
 
 (8,837)
 
 
 (1,630)
 
 
 451 
PSO
 
 
 652 
 
 
 325 
 
 
 - 
 
 
 (483)
 
 
 (471)
 
 
 23 
SWEPCo
 
 
 627 
 
 
 622 
 
 
 - 
 
 
 (1,620)
 
 
 405 
 
 
 34 

These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income.  The remaining liability is included in Other Current Liabilities on the condensed balance sheets.  Management does not expect additional costs to be incurred related to this initiative.

 
229
 

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 2012 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

Customer Demand

In comparison to 2012, weather-normalized retail sales across the AEP System were down 1.5% and 1.9% for the three and nine months ended September 30, 2013, respectively.  Industrial sales across the AEP System declined 3.9% and 5.1%, respectively, partially due to lower production levels at Ormet, a large aluminum company.

Repositioning Efforts

In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings.  This process has included evaluations of employee and retiree benefit programs as well as evaluations of the functional effectiveness and staffing levels of the AEP System’s finance and accounting, information technology, generation and supply chain and procurement organizations.  While certain aspects of this program have been completed, ongoing review of repositioning opportunities continues to yield cost savings for many of the Registrant Subsidiaries, allowing management to direct many of these savings into growth areas of the AEP System.

ENVIRONMENTAL ISSUES

The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with 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 (HAPs) from fossil fuel-fired power plants, proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.

The Registrant Subsidiaries are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of I&M’s nuclear units.  AEP, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court.  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.  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 2012 Annual Report.  Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Recovery in Ohio will be dependent upon prevailing market conditions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If the costs of environmental compliance are not recovered, it would reduce future net income and cash flows and impact financial condition.

 
230
 
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, 2013, the AEP System had a total generating capacity of 37,600 MWs, of which 23,700 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:

 
 
 
2013 Through 2020
 
 
 
Estimated Environmental Investment
Company
 
Low
 
High
 
 
(in millions) 
APCo
 
$
 330 
 
$
 380 
I&M
 
 
 440 
 
 
 500 
OPCo
 
 
 800 
 
 
 900 
PSO
 
 
 320 
 
 
 360 
SWEPCo
 
 
 1,060 
 
 
 1,220 

For APCo, the projected environmental investment above includes the conversion of 470 MWs of coal generation to natural gas capacity.  If natural gas conversion is not completed, the units could be closed sooner than planned.

The preceding discussion of environmental investments and plans for future years reflects the ownership of plants as of September 30, 2013.  The AEP East Companies have filed with the FERC to terminate the Interconnection Agreement and for OPCo to transfer facilities to APCo, KPCo and AEPGenCo.  Management expects the transfers will be effective December 31, 2013.

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.

Subject to the factors listed above and based upon continuing evaluation, management intends 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 1-4
 
 
 995 
OPCo
 
Kammer Plant
 
 
 630 
OPCo
 
Muskingum River Plant, Units 1-5
 
 
 1,440 
OPCo
 
Picway Plant
 
 
 100 
PSO
 
Northeastern Station, Unit 4
 
 
 470 
SWEPCo
 
Welsh Plant, Unit 2
 
 
 528 

As of September 30, 2013, the net book value of all of OPCo’s units above was zero and the net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the other plants in the table above was $752 million.
 
 
231
 

In the second quarter of 2013, management re-evaluated potential courses of action with respect to the planned operation of Muskingum River Plant, Unit 5 and concluded that completion of a refueling project which would extend the unit’s useful life is remote.  As a result, in the second quarter of 2013, management completed an impairment analysis and recorded a $154 million pretax ($99 million, net of tax) impairment charge for OPCo’s net book value of Muskingum River Plant, Unit 5.  Management expects to retire the plant no later than 2015.  See “Muskingum River Plant, Unit 5” section of Note 5.

In addition, management is in the process of obtaining permits and other necessary regulatory approvals for either the conversion of some coal units to natural gas or installing emission control equipment on certain units.  The following table lists the plants or units that are either awaiting regulatory approval or are still being evaluated by management based on changes in emission requirements and demand for power:

 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs) 
APCo
 
Clinch River Plant, Units 1-2
 
 
 470 
I&M/AEGCo/KPCo
 
Rockport Plant, Units 1-2
 
 
 2,620 
PSO
 
Northeastern Station, Unit 3
 
 
 460 
SWEPCo
 
Welsh Plant, Units 1& 3
 
 
 1,056 

As of September 30, 2013, the net book values before cost of removal, including related materials and supplies inventory and CWIP balances, of the plants in the table above were $1.3 billion.

Volatility in natural gas prices, pending environmental rules and other market factors could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of coal-fired units.  For regulated plants that may close early, management is seeking regulatory recovery of remaining net book values.  To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows.

Modification of the NSR Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between the AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when it undertook various equipment repair and replacement projects over a period of nearly 20 years.  The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOx emissions from the AEP System and various mitigation projects.

The original consent decree required certain types of control equipment to be installed at Muskingum River Plant, Unit 5, Big Sandy Plant, Unit 2 and the two units of the Rockport Plant in 2015, 2017 and 2019, respectively.  In January 2013, an agreement to modify the consent decree was reached and filed with the court.  The terms of the agreement include more options for the affected units (including alternative control technologies, re-fueling and/or retirement), more stringent SO2 emission caps for the AEP System and additional mitigation measures.  The Federal EPA sought public comments on the modification prior to its entry by the court in May 2013.  For the units of the Rockport Plant, the modified decree requires installation of dry sorbent injection technology for SO2 control on both units in 2015 and imposes a declining plant-wide cap on SO2 emissions beginning in 2016.

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
 
 
232
 
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 U.S. Court of Appeals for the District of Columbia Circuit and its fate is uncertain given developments in the CSAPR litigation.

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

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

Cross-State Air Pollution Rule (CSAPR)

In August 2011, the Federal EPA issued CSAPR.  Certain revisions to the rule were finalized in March 2012.  CSAPR relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states.  Interstate trading of allowances was 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 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 U.S. 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 filed petitions for rehearing but in January 2013, the U.S. Court of Appeals for the District of Columbia Circuit denied all petitions for rehearing.  The petition for further review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013.  Separate appeals of the supplemental rule, the Error Corrections Rule and the further revisions have been filed, but are being held in abeyance.

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
 
 
233
 
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 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards.  Revisions to the new source standards consistent with the proposed rule, except for the start-up and shut down provisions, were issued by the Federal EPA in March 2013.  The Federal EPA has reopened the public comment period to consider additional changes to the start-up and shut down provisions.
 
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 U.S. Court of Appeals for the District of Columbia Circuit by several organizations in which the Registrant Subsidiaries are members.  Certain issues related to the standards for new coal-fired units have been severed from the main case and are being held in abeyance pending completion of the Federal EPA’s reconsideration proceeding.  The case is proceeding on the remaining issues and briefing was completed in April 2013.

Regional Haze – Affecting PSO

In 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.  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 November 2012, PSO notified the court that the parties had reached agreement on a settlement 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 Tenth Circuit Court of Appeals is holding the appeal in abeyance pending implementation of the settlement.  A revised regional haze SIP has been adopted by the State of Oklahoma.  The Federal EPA proposed approval of the revised SIP.

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.  New source performance standards affect units that have not yet received permits.  The proposed standards were challenged in the U.S. Court of Appeals for the District of Columbia Circuit.  That case was dismissed because the court determined that no final agency action had yet been taken.

 
234
 
In June 2013, President Obama issued a memorandum to the Administrator of the Federal EPA directing the agency to develop and issue a new proposal regulating carbon emissions from new electric generating units in September 2013.  The new proposal was issued in September 2013 and requires new large natural gas units to meet 1,000 pounds of CO2 per MWh of electricity generated and small natural gas units to meet 1,100 pounds of CO2 per MWh.  New coal-fired units are required to meet the 1,100 pounds of CO2 per MWh with the option to meet the tighter limits if they choose to average emissions over multiple years.  The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from existing, modified and reconstructed electric generating units before June 2014, to finalize those standards by June 2015 and to require states to submit revisions to their implementation plans including such standards no later than June 2016.  The President directed the Federal EPA, in developing this proposal, to directly engage states, leaders in the power sector, labor leaders and other stakeholders, to tailor the regulations to reduce costs, to develop market-based instruments and allow regulatory flexibilities and “assure that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power.”  Management cannot currently predict the impact these programs may have on future resource plans or the existing generating fleet, but the costs may be substantial.

In June 2012, the U.S. 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 which the court denied in December 2012.  The U.S. Supreme Court granted several petitions for review and will determine whether the Federal EPA made a reasonable determination that adoption of the motor vehicle standards trigger PSD and Title V permitting obligations for stationary sources.  A decision is expected by June 2014.

The Federal EPA also finalized a rule in June 2012 that retains the current CO2 emission 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.

Coal Combustion Residual Rule

In 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 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. Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule.  The Federal EPA opposed the petition and is seeking additional time to coordinate the issuance of a final rule with the issuance of new effluent limitations under the Clean Water Act for utility facilities.  In October 2013, the U.S. District Court for the District of Columbia issued an order stating that it intended to partially rule in favor of the Federal EPA for dismissal of two counts and rule in favor of the environmental organizations on one count.  However, the court also stated that a Memorandum Opinion and Final Order would be forthcoming and until issued management is unable to predict the impact of the court’s ruling.

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
 
 
235
 
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 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 November 2013.  Management is preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

In addition, the Federal EPA issued an information collection request and is developing revised effluent limitation guidelines for electricity generating facilities.  A proposed rule was signed in April 2013 with a final rule expected in 2014.  The Federal EPA proposed eight options of increasing stringency and cost for fly ash and bottom ash transport water, scrubber wastewater, leachate from coal combustion byproduct landfills and impoundments and other wastewaters associated with coal-fired generating units, with four labeled preferred options.  Certain of the Federal EPA's preferred options have already been implemented or are part of the AEP System’s long-term plans.  Management will review the proposal in detail to evaluate whether the plants are currently meeting the proposed limitations, what technologies have been incorporated into the long-range plans and what additional costs might be incurred if the Federal EPA's most stringent options were adopted.  Management submitted detailed comments to the Federal EPA in September 2013 and participated in comments filed by various organizations of which the AEP System companies are members.

Climate Change

National public policy makers and regulators in the 10 states the Registrant Subsidiaries serve have diverse views on climate change.  Management is currently focused on responding to these emerging views with prudent actions, such as improving energy efficiency, investing in developing cost-effective and less carbon-intensive technologies and evaluating assets across a range of plausible scenarios and outcomes.  Management is also active participants in a variety of public policy discussions at state and federal levels to assure that proposed new requirements are feasible and the economies of the states served are not placed at a competitive disadvantage.

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.  The majority of the states where the Registrant Subsidiaries have generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements.  Management is taking steps to comply with these requirements.

Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others.  The Registrant Subsidiaries are no longer a party to any such cases.  See Note 4.

 
236
 
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 climate change, other environmental issues and the actions management is taking to address potential impacts, see Part I of the 2012 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters” and “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries.”

FINANCIAL CONDITION

BUDGETED CONSTRUCTION EXPENDITURES

The 2013 updated estimated construction expenditures by Registrant Subsidiary include generation, transmission and distribution related investments, as well as expenditures for compliance with environmental regulations as follows:

 
 
2013 Budgeted Construction Expenditures
Company
 
Environmental
 
Generation
 
Transmission
 
Distribution
 
Other
 
Total
 
 
 
(in millions)
APCo
 
$
 47 
 
$
 76 
 
$
 80 
 
$
 144 
 
$
 16 
 
$
 363 
I&M
 
 
 27 
 
 
 284 
 
 
 52 
 
 
 86 
 
 
 14 
 
 
 463 
OPCo
 
 
 151 
 
 
 89 
 
 
 132 
 
 
 222 
 
 
 33 
 
 
 627 
PSO
 
 
 58 
 
 
 39 
 
 
 56 
 
 
 140 
 
 
 11 
 
 
 304 
SWEPCo
 
 
 120 
 
 
 65 
 
 
 102 
 
 
 98 
 
 
 11 
 
 
 396 

For 2014 and 2015, management forecasts annual construction expenditures for the AEP System of $3.8 billion each year.  The budgeted amounts exclude equity AFUDC and capitalized interest.  The projected increases are generally the result of required environmental investment to comply with Federal EPA rules and additional transmission spending.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  These construction expenditures will be funded through cash flows from operations and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged.

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.  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 2013, 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,
 
 
237
 
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, 2013, 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 2013 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.     Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 4 incorporated herein by reference.

Item 1A.  Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2012 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 2012 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

In December 2012, SWEPCo placed the Turk Plant in Arkansas into commercial operation.  SWEPCo holds a 73% ownership interest in the 600 MW coal-fired generating facility.  SWEPCo had originally intended that the Arkansas jurisdictional share of the Turk Plant (approximately 20%) would become part of the rate base for its retail customers in Arkansas.  Following a proceeding at the Arkansas Supreme Court, the APSC issued an order which reversed and set aside a previously granted Certificate of Environmental Compatibility and Public Need.  The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market.  SWEPCo has included a request to recover a portion of the costs of the Turk Plant in its base rate case filed in Texas.  In addition, in February 2013, the LPSC granted recovery for a portion of the Turk Plant costs in a formula rate filing, subject to refund based on the staff review of the cost of service and prudence review of the Turk Plant.  If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant either through retail rates or sales into the wholesale market, it could reduce future net income and cash flows and impact financial condition.

Approved recovery related to extending the useful life of the Cook Plant may be overturned on appeal. – Affecting AEP and I&M

In April and May 2012, I&M filed petitions 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 intended to ensure the safe and reliable operation of the plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of September 30, 2013, I&M has incurred $285 million related to the LCM Project, including AFUDC.  In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.  If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

 
238
 
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.  A portion of the increase seeks recovery for costs associated with the construction and operation of the Texas jurisdictional share (approximately 33%) of the Turk Plant.  In October 2013, the PUCT issued an order that granted part of the requested rate recovery.  The order excluded, until SWEPCo files and obtains approval for a Transmission Cost Recovery Rider, the Turk Plant transmission line investment that was not in service at the end of the test year.  Additionally, the PUCT determined that it would defer consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.  As of September 30, 2013, the net book value of Welsh Plant, Unit 2 was $94 million, before cost of removal, including materials and supplies inventory and CWIP.  SWEPCo intends to file a motion for rehearing with the PUCT in late October 2013.

If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Turk Plant, transmission lines or Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

Request for rate recovery in Indiana may be overturned on appeal. – Affecting AEP and I&M

In February 2013, the IURC issued an order granting an annual increase in base rates.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the order with the Indiana Court of Appeals.  In September 2013, the OUCC filed a brief on appeal that included objections to certain aspects of the rate case.  If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

Request for rate recovery in Kentucky may not be approved in its entirety. – Affecting AEP

In June 2013, KPCo filed a request with the KPSC for annual increases in Kentucky base rates.  If the KPSC denies all or part of the requested rate recovery, it could reduce future net income and cash flows and impact financial condition.

RISKS RELATING TO STATE RESTRUCTURING

We are unable to fully predict the effects of the inter-company transfer of OPCo’s generation assets and terminating the Interconnection Agreement, – Affecting AEP, APCo, I&M and OPCo

In October 2012, we submitted several filings with the FERC seeking approval to fully separate OPCo’s generating assets from its distribution and transmission operations.  The filings requested approval to transfer approximately 9,200 MW of OPCo-owned generation assets to a new competitive, unregulated generation affiliate.  We also requested approval from the FERC and, as applicable, the KPSC, the Virginia SCC and the WVPSC to transfer 1,647 MW of OPCo-owned generation assets to APCo and 780 MW of OPCo-owned generation assets to KPCo.  These transfers are proposed to be effective December 31, 2013.  The transfer of generation units co-owned by third parties will require the consent and cooperation of those third parties.  In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AEPGenCo, the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo and the merger of APCo and WPCo.  In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo.  OPCo has contested the petition for rehearing, which remains pending before the FERC.

Additionally, we asked for FERC approval to terminate the existing Interconnection Agreement and to authorize a new Power Coordination Agreement among APCo, I&M and KPCo.  Significant gaps could emerge if the Interconnection Agreement is terminated without approval of the generation asset transfers and/or the new Power Coordination Agreement.  Surplus members would 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 would 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.  In addition, we can give no assurance that the FERC or other state commissions will not impose material adverse terms as a condition to approving these arrangements and asset transfers.  Further, third party co-owners may not consent to the transfers where applicable.

 
239
 
In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by recent orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation.

Customers are choosing alternative electric generation service providers, as allowed by Ohio law and regulation. – Affecting AEP and OPCo

Under current Ohio law, electric generation is sold in a competitive market in Ohio and native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service.  CRES providers are targeting retail customers by offering alternative generation service.  As customer switching in Ohio continues, it could reduce future net income and cash flows and impact financial condition.

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 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 and Conner Run under the Mine Act for the quarter ended September 30, 2013.

Item 5.  Other Information

None

Item 6.  Exhibits

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

 
240
 

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 25, 2013
 
 
241