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)
$
 
$
 
$
 
$
 
$
 
$
 
$
 
$

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