q213aep10q.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 June 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
July 25, 2013
       
American Electric Power Company, Inc.
    
486,772,596
     
($6.50 par value)
Appalachian Power Company
    
13,499,500
     
(no par value)
Indiana Michigan Power Company
    
1,400,000
     
(no par value)
Ohio Power Company
    
27,952,473
     
(no par value)
Public Service Company of Oklahoma
    
9,013,000
     
($15 par value)
Southwestern Electric Power Company
    
7,536,640
     
($18 par value)

 
 
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
June 30, 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
          
31
 
Index of Condensed Notes to Condensed Consolidated Financial Statements
      
37
                     
Appalachian Power Company and Subsidiaries:
              
 
Management’s Narrative Discussion and Analysis of Results of Operations
      
86
 
Condensed Consolidated Financial Statements
          
92
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
    
98
                     
Indiana Michigan Power Company and Subsidiaries:
              
 
Management’s Narrative Discussion and Analysis of Results of Operations
      
100
 
Condensed Consolidated Financial Statements
          
105
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
    
111
                     
Ohio Power Company and Subsidiary:
              
 
Management’s Narrative Discussion and Analysis of Results of Operations
      
113
 
Condensed Consolidated Financial Statements
          
120
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
    
126
                     
Public Service Company of Oklahoma:
              
 
Management’s Narrative Discussion and Analysis of Results of Operations
      
128
 
Condensed Financial Statements
            
132
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
    
138
                     
Southwestern Electric Power Company Consolidated:
            
 
Management’s Narrative Discussion and Analysis of Results of Operations
      
140
 
Condensed Consolidated Financial Statements
          
146
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
    
152
                     
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
      
153
                     
Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries
      
220
                     
Controls and Procedures
              
227
 
 
 
 
                     
Part II.  OTHER INFORMATION
              
                     
 
Item 1.
 Legal Proceedings          
228
 
Item 1A.
 Risk Factors
 
        
228
 
Item 2.
 Unregistered Sales of Equity Securities and Use of Proceeds  
229
 
Item 4.
 Mine Safety Disclosures
 
      
230
 
Item 5.
 Other Information
 
        
230
 
Item 6.
 Exhibits:
 
          
230
      Exhibit 4              
      Exhibit 10              
      Exhibit 12              
      Exhibit 31(a)              
      Exhibit 31(b)              
      Exhibit 32(a)              
      Exhibit 32(b)              
      Exhibit 95              
      Exhibit 101.INS              
      Exhibit 101.SCH              
      Exhibit 101.CAL              
      Exhibit 101.DEF              
      Exhibit 101.LAB              
      Exhibit 101.PRE              
                     
SIGNATURE
                
231
 
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
 
 
 
 Term
    Meaning
     
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.
OCC
  
Corporation Commission of the State of Oklahoma.
OPCo
  
Ohio Power Company, an AEP electric utility subsidiary.
OPEB
  
Other Postretirement Benefit Plans.
OTC
  
Over the counter.
PJM
  
Pennsylvania – New Jersey – Maryland regional transmission organization.
PM
  
Particulate Matter.
POLR
  
Provider of Last Resort revenues.
PSO
  
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
  
Public Utilities Commission of Ohio.
PUCT
  
Public Utility Commission of Texas.
Registrant Subsidiaries
  
AEP subsidiaries which are SEC registrants; APCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts
  
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
  
A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
RTO
  
Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine
  
Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC
  
U.S. Securities and Exchange Commission.
SEET
  
Significantly Excessive Earnings Test.
 
 
ii
 
 Term    Meaning
     
SIA
  
System Integration Agreement, effective June 15, 2000, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF
  
Spent Nuclear Fuel.
SO2
  
Sulfur dioxide.
SPP
  
Southwest Power Pool regional transmission organization.
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, including the implementation of ESPs and the transition to market and the legal separation of generation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.
·
Our ability to successfully manage negotiations with stakeholders and obtain regulatory approval to terminate 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.

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 the plant transfers discussed above.  We are currently pursuing cost recovery of these plants in Kentucky and West Virginia and plan to pursue cost recovery in Virginia.  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 strongly contested the petition for rehearing, which remains pending before the FERC.  In June 2013, a settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club was filed with the KPSC which supported the plant transfer discussed above.  The Attorney General was not party to the settlement agreement.  If approved, KPCo will withdraw the current base rate case request and current rates will remain in effect until at least May 2015.  Hearings in the plant transfer cases were held at the Virginia SCC in June 2013 and at the KPSC and WVPSC in July 2013.  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.

If 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.
 
1
 

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 June 30, 2013, OPCo’s net deferred fuel balance was $484 million, excluding unrecognized equity carrying costs.  Decisions from the Supreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance.
 
June 2012 – May 2015 Ohio ESP Including Capacity Charge
 
In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015, which was generally upheld in rehearing orders in January and March 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The RPM price is approximately $33/MW day through May 2014.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.  As of June 30, 2013, OPCo’s incurred deferred capacity costs balance was $171 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 is expected to provide approximately $500 million of revenue over the ESP period and will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs.

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 $160 million through May 2015. 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. 

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.

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.
 
2
 

Customer Demand

In comparison to 2012, our weather-normalized retail sales were down 2.7% and 2.1% for the three and six months ended June 30, 2013, respectively.  Our industrial sales declined 5.3% and 5.7%, respectively, partially due to Ormet, a large aluminum company that lowered their production in the third quarter of 2012 by one-third and is currently in bankruptcy proceedings.

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.  Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings.  OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO-ordered SEET refund.  OPCo is required to file its 2011 SEET filing with the PUCO 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.

U.K. Windfall Tax Decision

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

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 June 30, 2013, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital cost cap, SWEPCo has capitalized approximately $1.8 billion of expenditures, including AFUDC and capitalized interest of $328 million and related transmission costs of $118 million.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the 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 SPP 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.
 
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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 December 2012, several intervenors filed opposing testimony and in May 2013, the ALJ issued a proposal for decision (PFD) and added clarifications to the PFD in July 2013.  The PFD, as clarified, made various recommendations including (a) an annual base rate increase of approximately $41 million based upon a return on common equity of 9.65%, (b) the disallowance of the Turk Plant capital costs in excess of the investment and committed costs as of June 2010 plus the cost to retrofit Welsh Plant, Unit 2 which, as of June 30, 2013, SWEPCo estimates could result in a write-off of approximately $74 million (in excess of the $62 million reserve previously recorded related to the Texas capital cost cap) and (c) the exclusion, until SWEPCo’s next Texas base rate case, of the Turk Plant transmission line investment that was not in service at the end of the test year.  A decision from the PUCT is expected in the third quarter of 2013.  If the PUCT does not approve full cost recovery of SWEPCo’s Texas jurisdictional share of assets, 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 all non-fuel Turk Plant costs and a full weighted-average cost of capital return on the Turk Plant portion of 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 filed an appeal of the order with the Indiana Court of Appeals.  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.

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 the cost recovery of the pending transfer of the one-half interest in the Mitchell Plant, cost recovery of Big Sandy Plant, Units 1 and 2 and includes requests for recovery of deferrals related to the Big Sandy Plant FGD project and 2012 storm costs.  Also in June 2013, a settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club was filed with the KPSC which supported the Mitchell plant transfer discussed above.  If the settlement agreement is approved, KPCo will withdraw this base rate case request and current rates will remain in effect until at least May 2015.  If KPCo is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows and impact financial condition.  See the “2013 Kentucky Base Rate Case” section of Note 3.
 
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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 June 30, 2013, I&M has incurred $240 million related to the LCM Project, including AFUDC.

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

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON.  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.

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.

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.
 
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Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of June 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, investments to meet these proposed requirements range from approximately $4 billion to $5 billion through 2020.  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.

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 1-3
    
 495 
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
        
 6,033 

As of June 30, 2013, the net book value of all of OPCo’s units above is zero and the net book value including related inventory and CWIP balances of the other plants in the table above was $873 million.

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.
 
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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 
I&M
  
Tanners Creek Plant, Unit 4
    
 500 
KPCo
  
Big Sandy Plant, Unit 1
    
 278 
PSO
  
Northeastern Station, Unit 3
    
 460 
Total
        
 4,328 

As of June 30, 2013, the net book value including related inventory and CWIP balances of the plants in the table above was $1.3 billion.

Volatility in natural gas prices, pending environmental rules and other market factors could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of coal-fired units.  For regulated plants that 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.

Modification of the New Source Review (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 consent decree requires 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.  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 of its units at the Rockport Plant with a Dry Sorbent Injection system.  The estimated cost in the application was $285 million, excluding AFUDC.  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 direct ownership share.  Hearings at the IURC are scheduled for August 2013.  A decision is expected by November 2013.  As of June 30, 2013, we have incurred costs of $77 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.
 
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Flint Creek Plant Environmental Controls

In 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA.  The estimated cost of the project is $408 million, excluding AFUDC and company overheads.  SWEPCo’s portion of those costs is estimated at $204 million.  As of June 30, 2013, SWEPCo has incurred $24 million related to this project, including AFUDC and company overheads.  In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant.  See the “Flint Creek Plant Environmental Controls” 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.  The plan requested approval for (a) an estimated $210 million of new environmental investment, excluding AFUDC and overheads of $46 million, that will be incurred prior to 2016 at NES Unit 3, (b) accelerated recovery through 2026 of the net book value of NES Units 3 and 4 (combined net book value of the two units is $231 million as of June 30, 2013), (c) an estimated $83 million of new investment incurred through 2016 at various gas units and (d) a new 15-year purchase power agreement with a nonaffiliated entity, effective in 2016, with cost recovery through a rider, including an annual earnings component of $3 million.  Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery in a future rate proceeding.

In January 2013, several parties filed testimony with various recommendations.  In March 2013, the OCC granted a stay in this proceeding.  In July 2013, the OCC staff filed a motion to lift the stay and dismiss PSO’s environmental compliance plan case without prejudice.  A hearing on the motion will be held in August 2013.  If this case is dismissed, 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.  See “Oklahoma Environmental Compliance Plan” section of Note 3.

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.
 
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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.

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. 
 
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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 and submitted to the Federal EPA for review.

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.  A proposal was sent to the Office of Management and Budget for interagency review the following week, but the details of the proposal are not known.  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.  In developing this proposal, the President directed the Federal EPA 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.  Petitioners filed petitions for further review in the U.S. Supreme Court.
 
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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 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.

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.
 
11
 

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 plan to submit detailed comments to the Federal EPA.

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.

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 have been named in one remaining pending lawsuit, which we are defending.  It is not possible to predict the outcome of this lawsuit or its impact on our operations or financial condition.  See “Carbon Dioxide Public Nuisance Claims” section of Note 4.

Future federal and state legislation or regulations that mandate limits on the emission of CO2 would result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force 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.”
 
12
 

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 six months ended June 30, 2013 and 2012.

   
Three Months Ended June 30,
  
Six Months Ended June 30,
   
2013 
  
2012 
  
2013 
  
2012 
   
(in millions)
Utility Operations
$
 222 
  
$
 365 
  
$
 571 
  
$
 749 
Transmission Operations
  
 18 
    
 8 
    
 31 
    
 17 
AEP River Operations
  
 (9)
    
 3 
    
 (11)
    
 12 
Generation and Marketing
  
 4 
    
 (5)
    
 11 
    
 (6)
All Other (a)
  
 104 
    
 (8)
    
 101 
    
 (19)
Net Income
$
 339 
  
$
 363 
  
$
 703 
  
$
 753 

(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.

 
13
 
AEP CONSOLIDATED

Second Quarter of 2013 Compared to Second Quarter of 2012

Net Income decreased from $363 million in 2012 to $339 million in 2013 primarily due to:

·
The second quarter 2013 impairment of Muskingum River Plant, Unit 5.
·
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.
·
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.
·
A decrease in weather-related usage.
·
An increase in storm-related expenses during the second quarter of 2013.

These decreases were partially offset by:

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

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Net Income decreased from $753 million in 2012 to $703 million in 2013 primarily due to:

·
The second quarter 2013 impairment of Muskingum River Plant, Unit 5.
·
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 weak demand for grain and coal and river conditions in the first quarter of 2013.
·
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.
·
A first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of the Ohio modified stipulation.

These decreases were partially offset by:

·
Successful rate proceedings in our various jurisdictions.
·
A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.
·
The deferral of Ohio capacity costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
·
An increase in weather-related usage in the first quarter of 2013.

Our results of operations are discussed below by operating segment.
 
14
 

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
  
Six Months Ended
   
June 30,
  
June 30,
   
2013 
  
2012 
  
2013 
  
2012 
   
(in millions)
Revenues
$
 3,278 
  
$
 3,258 
  
$
 6,795 
  
$
 6,643 
Fuel and Purchased Electricity
  
 1,130 
    
 1,096 
    
 2,407 
    
 2,365 
Gross Margin
  
 2,148 
    
 2,162 
    
 4,388 
    
 4,278 
Other Operation and Maintenance
  
 806 
    
 770 
    
 1,685 
    
 1,525 
Asset Impairments and Other Related Charges
  
 154 
    
 - 
    
 154 
    
 - 
Depreciation and Amortization
  
 429 
    
 448 
    
 835 
    
 860 
Taxes Other Than Income Taxes
  
 213 
    
 202 
    
 422 
    
 413 
Operating Income
  
 546 
    
 742 
    
 1,292 
    
 1,480 
Interest and Investment Income
  
 6 
    
 2 
    
 9 
    
 3 
Carrying Costs Income
  
 8 
    
 11 
    
 12 
    
 31 
Allowance for Equity Funds Used During Construction
  
 10 
    
 20 
    
 20 
    
 40 
Interest Expense
  
 (221)
    
 (224)
    
 (447)
    
 (441)
Income Before Income Tax Expense and Equity
                      
 
Earnings
  
 349 
    
 551 
    
 886 
    
 1,113 
Income Tax Expense
  
 127 
    
 186 
    
 315 
    
 365 
Equity Earnings of Unconsolidated Subsidiaries
  
 - 
    
 - 
    
 - 
    
 1 
Net Income
$
 222 
  
$
 365 
  
$
 571 
  
$
 749 

Summary of KWh Energy Sales for Utility Operations
                         
   
Three Months Ended
  
Six Months Ended
   
June 30,
  
June 30,
 
2013 
  
2012 
  
2013 
  
2012 
   
(in millions of KWhs)
Retail:
                      
 
Residential
  
 12,630 
    
 13,155 
    
 28,885 
    
 27,954 
 
Commercial
  
 12,553 
    
 13,087 
    
 24,104 
    
 24,353 
 
Industrial
  
 14,601 
    
 15,422 
    
 28,363 
    
 30,069 
 
Miscellaneous
  
 747 
    
 779 
    
 1,455 
    
 1,500 
Total Retail (a)
  
 40,531 
    
 42,443 
    
 82,807 
    
 83,876 
                       
Wholesale
  
 9,180 
    
 8,620 
    
 20,204 
    
 17,533 
                       
Total KWhs
  
 49,711 
    
 51,063 
    
 103,011 
    
 101,409 
                         
(a)  Represents energy delivered to distribution customers.

 
15
 
Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.  In general, degree day changes in our eastern region have a larger effect on net income than changes in our western region due to the relative size of the two regions and the number of customers within each region.

Summary of Heating and Cooling Degree Days for Utility Operations
                         
   
Three Months Ended
  
Six Months Ended
   
June 30,
June 30,
   
2013 
  
2012 
  
2013 
  
2012 
   
(in degree days)
Eastern Region
                      
Actual - Heating (a)
  
 167 
    
 118 
    
 1,985 
    
 1,379 
Normal - Heating (b)
  
 161 
    
 165 
    
 1,880 
    
 1,916 
                         
Actual - Cooling (c)
  
 351 
    
 401 
    
 351 
    
 429 
Normal - Cooling (b)
  
 306 
    
 300 
    
 310 
    
 303 
                         
Western Region
                      
Actual - Heating (a)
  
 54 
    
 1 
    
 606 
    
 348 
Normal - Heating (b)
  
 18 
    
 20 
    
 587 
    
 601 
                         
Actual - Cooling (d)
  
 797 
    
 961 
    
 867 
    
 1,094 
Normal - Cooling (b)
  
 786 
    
 774 
    
 848 
    
 834 
                         
(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.

 
16
 

Second Quarter of 2013 Compared to Second Quarter of 2012
               
Reconciliation of Second Quarter of 2012 to Second Quarter of 2013
Net Income from Utility Operations
(in millions)
               
Second Quarter of 2012
        
$
 365 
               
Changes in Gross Margin:
            
Retail Margins
          
 7 
Off-system Sales
          
 (46)
Transmission Revenues
          
 13 
Other Revenues
          
 12 
Total Change in Gross Margin
          
 (14)
             
Changes in Expenses and Other:
            
Other Operation and Maintenance
          
 (36)
Asset Impairments and Other Related Charges
          
 (154)
Depreciation and Amortization
          
 19 
Taxes Other Than Income Taxes
          
 (11)
Interest and Investment Income
          
 4 
Carrying Costs Income
          
 (3)
Allowance for Equity Funds Used During Construction
          
 (10)
Interest Expense
          
 3 
Total Change in Expenses and Other
          
 (188)
               
Income Tax Expense
          
 59 
               
Second Quarter of 2013
        
$
 222 

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

·
Retail Margins increased $7 million primarily due to the following:
 
·
Successful rate proceedings in our service territories which include:
   
·
An $85 million rate increase for OPCo.
   
·
A $44 million rate increase for I&M.
   
·
A $24 million rate increase for SWEPCo.
       
For the rate increases described above, $48 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
 
·
A $26 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 $66 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 $46 million increase in other variable electric generation expenses.
 
·
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 $28 million decrease in weather-related usage primarily due to 12% and 17% decreases in cooling degree days in our eastern and western regions, respectively.
·
Margins from Off-system Sales decreased $46 million 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.  The decrease in CRES capacity revenues is partially offset in other expense items below.
·
Transmission Revenues increased $13 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.
·
Other Revenues increased $12 million primarily due to increases in gains on other miscellaneous sales.

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

·
Other Operation and Maintenance expenses increased $36 million primarily due to the following:
 
·
A $21 million increase in storm-related expenses.
 
·
A $20 million increase in plant outages.
 
·
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.
 
·
A $12 million increase in energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
 
These increases were partially offset by:
 
·
A $13 million decrease in administrative and general expenses.
 
·
A $13 million decrease due to expenses recorded in 2012 related to the 2012 sustainable cost reductions program.
 
·
A $12 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.
·
Asset Impairments and Other Related Charges increased by $154 million due to the second quarter 2013 impairment of Muskingum River Plant, Unit 5.
·
Depreciation and Amortization expenses decreased $19 million primarily due to the following:
 
·
A $26 million decrease as a result of depreciation ceasing on certain Ohio generating plants that were impaired in November 2012.
 
·
A $15 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:
 
·
An $11 million increase due to the Turk Plant being placed in service in December 2012.
 
·
Overall higher depreciable property balances.
·
Taxes Other Than Income Taxes increased $11 million primarily due to increased property taxes as a result of increased capital investments.
·
Allowance for Equity Funds Used During Construction decreased $10 million primarily due to completed construction of the Turk Plant in December 2012.
·
Income Tax Expense decreased $59 million primarily due to a decrease in pretax book income.

 
18
 

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
               
Reconciliation of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2013
Net Income from Utility Operations
(in millions)
               
Six Months Ended June 30, 2012
        
$
 749 
               
Changes in Gross Margin:
            
Retail Margins
          
 125 
Off-system Sales
          
 (75)
Transmission Revenues
          
 35 
Other Revenues
          
 25 
Total Change in Gross Margin
          
 110 
             
Changes in Expenses and Other:
            
Other Operation and Maintenance
          
 (160)
Asset Impairments and Other Related Charges
          
 (154)
Depreciation and Amortization
          
 25 
Taxes Other Than Income Taxes
          
 (9)
Interest and Investment Income
          
 6 
Carrying Costs Income
          
 (19)
Allowance for Equity Funds Used During Construction
          
 (20)
Interest Expense
          
 (6)
Equity Earnings of Unconsolidated Subsidiaries
          
 (1)
Total Change in Expenses and Other
          
 (338)
               
Income Tax Expense
          
 50 
               
Six Months Ended June 30, 2013
        
$
 571 

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 $125 million primarily due to the following:
 
·
Successful rate proceedings in our service territories which include:
   
·
A $146 million rate increase for OPCo.
   
·
A $52 million rate increase for I&M.
   
·
A $47 million rate increase for SWEPCo.
   
·
A $21 million rate increase for APCo.
       
For the rate increases described above, $109 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
 
·
A $50 million net increase in weather-related usage in our eastern and western regions primarily due to increases of 44% and 74%, respectively, in heating degree days in our eastern and western regions, respectively, partially offset by decreases in cooling degree days of 18% and 21% in our eastern and western regions, respectively.
 
·
A $47 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 $153 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 $66 million increase in other variable electric generation expenses.
 
·
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.
·
Margins from Off-system Sales decreased $75 million 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, partially offset by higher physical sales volumes and margins.  The decrease in CRES capacity revenues is partially offset in other expense items below.
 
 
19
 
·
Transmission Revenues increased $35 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.
·
Other Revenues increased $25 million primarily due to increases in gains on other miscellaneous sales.

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

·
Other Operation and Maintenance expenses increased $160 million primarily due to the following:
 
·
A $45 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 $42 million increase in plant outages during 2013.
 
·
A $35 million increase due to the first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of the Ohio modified stipulation.
 
·
A $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 $28 million increase in energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
 
·
A $26 million increase in storm-related expenses primarily in APCo's service territory.
 
These increases were partially offset by:
 
·
A $25 million decrease due to an agreement reached to settle an insurance claim in the first quarter of 2013.
 
·
A $20 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.
·
Asset Impairments and Other Related Charges increased $154 million due to the second quarter 2013 impairment of Muskingum River Plant, Unit 5.
·
Depreciation and Amortization expenses decreased $25 million primarily due to the following:
 
·
A $53 million decrease as a result of depreciation ceasing on certain Ohio generating plants that were impaired in November 2012.
 
·
A $35 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 $22 million increase due to the Turk Plant being placed in service in December 2012.
 
·
Overall higher depreciable property balances.
·
Taxes Other Than Income Taxes increased $9 million primarily due to increased property taxes as a result of increased capital investments.
·
Carrying Costs Income decreased $19 million primarily due to the following:
 
·
A $10 million decrease due to an increased recovery of Virginia environmental costs in new base rates as approved by the Virginia SCC in late January 2012 and decreased carrying charges related to the Dresden Plant.
 
·
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 $20 million primarily due to completed construction of the Turk Plant in December 2012.
·
Income Tax Expense decreased $50 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.

 
20
 
TRANSMISSION OPERATIONS

Second Quarter of 2013 Compared to Second Quarter of 2012

Net Income from our Transmission Operations segment increased from $8 million in 2012 to $18 million in 2013 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Net Income from our Transmission Operations segment increased from $17 million in 2012 to $31 million in 2013 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT.

AEP RIVER OPERATIONS

Second Quarter of 2013 Compared to Second Quarter of 2012

Net Income from our AEP River Operations segment decreased from income of $3 million in 2012 to a loss of $9 million in 2013 primarily due to weak demand for grain and coal.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Net Income from our AEP River Operations segment decreased from income of $12 million in 2012 to a loss of $11 million in 2013 primarily due to weak demand for grain and coal and the 2012 drought which continued to have negative impacts on river conditions in the first quarter of 2013.

GENERATION AND MARKETING

Second Quarter of 2013 Compared to Second Quarter of 2012

Net Income from our Generation and Marketing segment increased from a loss of $5 million in 2012 to income of $4 million in 2013 primarily due to higher trading and marketing margins and increased retail activity.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Net Income from our Generation and Marketing segment increased from a loss of $6 million in 2012 to income of $11 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

Second Quarter of 2013 Compared to Second Quarter of 2012

Net Income from All Other increased from a loss of $8 million in 2012 to income of $104 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.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Net Income from All Other increased from a loss of $19 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.
 
21
 

AEP SYSTEM INCOME TAXES

Second Quarter of 2013 Compared to Second Quarter of 2012

Income Tax Expense decreased $122 million primarily due to the recognition of the tax benefits associated with the U.K. Windfall Tax decision and a decrease in pre-tax book income.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Income Tax Expense decreased $116 million primarily due to the recognition of the tax benefits associated with the U.K. Windfall Tax decision and a decrease in pre-tax book income, partially offset by audit settlements for previous years recorded in 2012.

FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

   
June 30, 2013
  
December 31, 2012
   
(dollars in millions)
Long-term Debt, including amounts due within one year
$
 17,618 
  
 50.8 
%
  
$
 17,757 
  
 52.3 
%
Short-term Debt
  
 1,538 
  
 4.4 
      
 981 
  
 2.9 
  
Total Debt
  
 19,156 
  
 55.2 
      
 18,738 
  
 55.2 
  
AEP Common Equity
  
 15,537 
  
 44.8 
      
 15,237 
  
 44.8 
  
                       
Total Debt and Equity Capitalization
$
 34,693 
  
 100.0 
%
  
$
 33,975 
  
 100.0 
%

Our ratio of debt-to-total capital remained unchanged at 55.2% as of December 31, 2012 and June 30, 2013.  Short-term debt outstanding increased primarily due to borrowing for our commercial paper program under credit facilities and our common equity increased due to 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 June 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.
 
22
 

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  As of June 30, 2013, our available liquidity was approximately $3.4 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
    
 117 
      
Total Liquidity Sources
    
 4,617 
      
Less:
AEP Commercial Paper Outstanding
    
 850 
      
 
Letters of Credit Issued
    
 120 
      
 
Draw on Term Credit Facility
    
 200 
      
               
Net Available Liquidity
  
$
 3,447 
      

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 six months of 2013 was $866 million.  The weighted-average interest rate for our commercial paper during 2013 was 0.34%.

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 now expire in June 2014.  The remaining commitment of $315 million expires in June 2015.

West Virginia Securitization of Regulatory Assets

In March 2012, West Virginia passed securitization legislation which allows the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred Expanded Net Energy Charge (ENEC) balances and other ENEC related assets.  In August 2012, APCo and WPCo filed with the WVPSC a request for a financing order to securitize $422 million related to APCo’s December 2011 under-recovered ENEC deferral balance, other ENEC-related assets and related financing costs.  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.  Hearings at the WVPSC are scheduled for July 2013.
 
23
 

Ohio Securitization of Regulatory Assets

In March 2013, the PUCO approved OPCo’s request to securitize the Deferred Asset Recovery Rider (DARR) balance.  As of June 30, 2013, OPCo’s DARR balance was $268 million, including $126 million of unrecognized equity carrying costs.  The DARR is being recovered through 2018 by a non-bypassable rider.  Once the securitization bonds are issued, the DARR will cease and will be replaced by the Deferred Asset Phase-in Rider, which will recover the securitized asset over a period not to exceed eight years.  The securitization bonds are expected to be issued in the third quarter of 2013.

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 June 30, 2013, this contractually-defined percentage was 51.6%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  As of June 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 June 30, 2013, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.49 per share in July 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.
 
24
 

CASH FLOW

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

     
Six Months Ended
     
June 30,
     
2013 
  
2012 
     
(in millions)
Cash and Cash Equivalents at Beginning of Period
  
$
 279 
  
$
 221 
Net Cash Flows from Operating Activities
    
 1,516 
    
 1,713 
Net Cash Flows Used for Investing Activities
    
 (1,643)
    
 (1,530)
Net Cash Flows Used for Financing Activities
    
 (35)
    
 (107)
Net Increase (Decrease) in Cash and Cash Equivalents
    
 (162)
    
 76 
Cash and Cash Equivalents at End of Period
  
$
 117 
  
$
 297 

Cash from operations and short-term borrowings provides working capital and allows us to meet other short-term cash needs.
 
Operating Activities
               
     
Six Months Ended
     
June 30,
     
2013 
  
2012 
     
(in millions)
Net Income
  
$
 703 
  
$
 753 
Depreciation and Amortization
    
 863 
    
 883 
Other
    
 (50)
    
 77 
Net Cash Flows from Operating Activities
  
$
 1,516 
  
$
 1,713 

Net Cash Flows from Operating Activities were $1.5 billion in 2013 consisting primarily of Net Income of $703 million, $863 million of noncash Depreciation and Amortization and $154 million of Asset Impairments related to Muskingum River Plant, Unit 5 partially offset by $102 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 $1.7 billion in 2012 consisting primarily of Net Income of $753 million and $883 million of noncash Depreciation and Amortization.  Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  A significant change in other items includes the favorable impact of a decrease in accounts receivable and the unfavorable impact of an increase in fuel inventory due to the mild winter weather.  Cash was also used to pay real and personal property taxes and to reduce accounts payable.  Deferred Income Taxes increased primarily due to provisions in the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Jobs Creation Act and an increase in tax versus book temporary differences from operations.
 
25
 
 
Investing Activities
               
     
Six Months Ended
     
June 30,
     
2013 
  
2012 
     
(in millions)
Construction Expenditures
  
$
 (1,637)
  
$
 (1,371)
Acquisitions of Nuclear Fuel
    
 (59)
    
 (11)
Acquisitions of Assets/Businesses
    
 (4)
    
 (88)
Insurance Proceeds Related to Cook Plant Fire
    
 72 
    
 - 
Proceeds from Sales of Assets
    
 11 
    
 8 
Other
    
 (26)
    
 (68)
Net Cash Flows Used for Investing Activities
  
$
 (1,643)
  
$
 (1,530)

Net Cash Flows Used for Investing Activities were $1.6 billion in 2013 primarily due to Construction Expenditures for environmental, distribution and transmission investments.

Net Cash Flows Used for Investing Activities were $1.5 billion in 2012 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments.  Acquisitions of Assets/Businesses include our March 2012 purchase of BlueStar for $70 million.
 
Financing Activities
               
     
Six Months Ended
     
June 30,
     
2013 
  
2012 
     
(in millions)
Issuance of Common Stock, Net
  
$
 41 
  
$
 50 
Issuance of Debt, Net
    
 425 
    
 332 
Dividends Paid on Common Stock
    
 (469)
    
 (458)
Other
    
 (32)
    
 (31)
Net Cash Flows Used for Financing Activities
  
$
 (35)
  
$
 (107)

Net Cash Flows Used for Financing Activities in 2013 were $35 million.  Our net debt issuances were $425 million. The net issuances included issuances of $475 million of senior unsecured notes, a $200 million draw on a $1 billion term credit facility, $170 million of pollution control bonds, $101 million of notes payable and an increase in short-term borrowing of $557 million offset by retirements of $796 million of senior unsecured and other debt notes, $131 million of securitization bonds and $146 million of pollution control bonds.  We paid common stock dividends of $469 million.  See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

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

In July 2013, I&M retired $12 million of Notes Payable related to DCC Fuel.
 
In July 2013, OPCo retired $65 million of 4.9% Pollution Control Bonds due in 2037 and issued $65 million of variable rate Pollution Control Bonds due in 2014.
 
26
 

OFF-BALANCE SHEET ARRANGEMENTS

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

     
June 30,
  
December 31,
     
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.

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.
 
27
 

We employ risk management contracts including physical forward purchase-and-sale contracts and financial forward purchase-and-sale contracts.  We engage in risk management of power, coal and natural gas and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business.  As a result, we are subject to price risk.  The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.  Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures.  The CORC consists of our Chief Operating Officer, Chief Financial Officer, 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 CORC.

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)
 
Six Months Ended June 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
  
 (17)
    
 (11)
    
 (28)
Fair Value of New Contracts at Inception When Entered During the
                
 
Period (a)
  
 - 
    
 10 
    
 10 
Changes in Fair Value Due to Market Fluctuations During the
                
 
Period (b)
  
 1 
    
 13 
    
 14 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
  
 12 
    
 - 
    
 12 
Total MTM Risk Management Contract Net Assets
                
 
as of June 30, 2013
$
 64 
  
$
 140 
    
 204 
                   
Commodity Cash Flow Hedge Contracts
              
 2 
Interest Rate and Foreign Currency Cash Flow Hedge Contracts
              
 (2)
Fair Value Hedge Contracts
              
 (12)
Collateral Deposits
              
 20 
Total MTM Derivative Contract Net Assets as of June 30, 2013
            
$
 212 

(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.
 
28
 

Credit Risk

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

We have risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily.  As of June 30, 2013, our credit exposure net of collateral to sub investment grade counterparties was approximately 8.1%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).  As of June 30, 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
  
$
 594 
  
$
 1 
  
$
 593 
    
 2 
  
$
 263 
Split Rating
    
 1 
    
 1 
    
 - 
    
 - 
    
 - 
Noninvestment Grade
    
 1 
    
 1 
    
 - 
    
 1 
    
 - 
No External Ratings:
                              
 
Internal Investment Grade
    
 71 
    
 - 
    
 71 
    
 3 
    
 29 
 
Internal Noninvestment Grade
    
 69 
    
 11 
    
 58 
    
 2 
    
 40 
Total as of June 30, 2013
  
$
 736 
  
$
 14 
  
$
 722 
    
 8 
  
$
 332 
                                 
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 June 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

Six Months Ended
  
Twelve Months Ended
June 30, 2013
  
December 31, 2012
End
  
High
  
Average
  
Low
  
End
  
High
  
Average
  
Low
(in millions)
  
(in millions)
$
- 
  
$
1 
  
$
- 
  
$
- 
  
$
- 
  
$
1 
  
$
- 
  
$
- 

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

 
29
 
As our VaR calculation captures recent price movements, we also perform regular stress testing of the portfolio to understand our exposure to extreme price movements.  We employ a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which historical price movements translated into the largest potential MTM loss.  We then research the underlying positions, price movements and market events that created the most significant exposure and report the findings to the Risk Executive Committee or the CORC as appropriate.

Interest Rate Risk

We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which our interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on debt outstanding as of June 30, 2013 and December 31, 2012, the estimated EaR on our debt portfolio for the following twelve months was $39 million and $42 million, respectively.

 
30
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2013 and 2012
 (in millions, except per-share and share amounts)
(Unaudited)
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
REVENUES
                        
Utility Operations
  
$
 3,253 
  
$
 3,235 
  
$
 6,742 
  
$
 6,598 
Other Revenues
    
 329 
    
 316 
    
 666 
    
 578 
TOTAL REVENUES
    
 3,582 
    
 3,551 
    
 7,408 
    
 7,176 
EXPENSES
                        
Fuel and Other Consumables Used for Electric Generation
    
 908 
    
 904 
    
 1,939 
    
 1,957 
Purchased Electricity for Resale
    
 359 
    
 268 
    
 730 
    
 528 
Other Operation
    
 664 
    
 719 
    
 1,402 
    
 1,375 
Maintenance
    
 285 
    
 252 
    
 578 
    
 514 
Asset Impairments and Other Related Charges
    
 154 
    
 - 
    
 154 
    
 - 
Depreciation and Amortization
    
 443 
    
 460 
    
 863 
    
 883 
Taxes Other Than Income Taxes
    
 222 
    
 207 
    
 440 
    
 424 
TOTAL EXPENSES
    
 3,035 
    
 2,810 
    
 6,106 
    
 5,681 
                           
OPERATING INCOME
    
 547 
    
 741 
    
 1,302 
    
 1,495 
                           
Other Income (Expense):
                        
Interest and Investment Income
    
 49 
    
 2 
    
 52 
    
 4 
Carrying Costs Income
    
 8 
    
 11 
    
 12 
    
 31 
Allowance for Equity Funds Used During Construction
    
 17 
    
 24 
    
 32 
    
 47 
Interest Expense
    
 (228)
    
 (235)
    
 (460)
    
 (464)
                           
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
    
 393 
    
 543 
    
 938 
    
 1,113 
                           
Income Tax Expense
    
 68 
    
 190 
    
 263 
    
 379 
Equity Earnings of Unconsolidated Subsidiaries
    
 14 
    
 10 
    
 28 
    
 19 
                           
NET INCOME
    
 339 
    
 363 
    
 703 
    
 753 
                           
Net Income Attributable to Noncontrolling Interests
    
 1 
    
 1 
    
 2 
    
 2 
                           
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
  
$
 338 
  
$
 362 
  
$
 701 
  
$
 751 
                           
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
    
486,293,026 
    
484,500,029 
    
486,059,643 
    
484,164,065 
                           
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
                        
 
SHAREHOLDERS
  
$
 0.69 
  
$
 0.75 
  
$
 1.44 
  
$
 1.55 
                           
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
    
486,763,615 
    
484,860,690 
    
486,555,121 
    
484,554,779 
                           
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
                        
 
SHAREHOLDERS
  
$
 0.69 
  
$
 0.75 
  
$
 1.44 
  
$
 1.55 
                           
CASH DIVIDENDS DECLARED PER SHARE
  
$
 0.49 
  
$
 0.47 
  
$
 0.96 
  
$
 0.94 
                           
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 37.
                        

 
31
 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2013 and 2012
(in millions)
(Unaudited)
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
Net Income
  
$
 339 
  
$
 363 
  
$
 703 
  
$
 753 
                           
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                        
Cash Flow Hedges, Net of Tax of $5 and $5 for the Three Months Ended
                        
 
June 30, 2013 and 2012, Respectively, and $8 and $11 for the Six
                        
 
Months Ended June 30, 2013 and 2012, Respectively
    
 (10)
    
 (10)
    
 14 
    
 (21)
Securities Available for Sale, Net of Tax of $- and $- for the Three Months
                        
 
Ended June 30, 2013 and 2012, Respectively, and $- and $1 for the
                        
 
Six Months Ended June 30, 2013 and 2012, Respectively
    
 - 
    
 (1)
    
 1 
    
 1 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $2
                        
 
and $4 for the Three Months Ended June 30, 2013 and 2012,
                        
 
Respectively, and $5 and $8 for the Six Months Ended June 30,
                        
 
2013 and 2012, Respectively
    
 3 
    
 8 
    
 9 
    
 15 
                           
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
    
 (7)
    
 (3)
    
 24 
    
 (5)
                           
TOTAL COMPREHENSIVE INCOME
    
 332 
    
 360 
    
 727 
    
 748 
                           
Total Comprehensive Income Attributable to Noncontrolling Interests
    
 1 
    
 1 
    
 2 
    
 2 
                         
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
                        
 
COMMON SHAREHOLDERS
  
$
 331 
  
$
 359 
  
$
 725 
  
$
 746 
                           
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 37.

 
32
 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 30, 2013 and 2012
(in millions)
(Unaudited)
                                               
 
AEP Common Shareholders
        
 
Common Stock
          
Accumulated
        
                 
Other
        
         
Paid-in
  
Retained
  
Comprehensive
  
Noncontrolling
    
 
Shares
  
Amount
  
Capital
  
Earnings
  
Income (Loss)
  
Interests
  
Total
TOTAL EQUITY – DECEMBER 31, 2011
  
 504 
  
$
 3,274 
  
$
 5,970 
  
$
 5,890 
  
$
 (470)
  
$
 1 
  
$
 14,665 
                                         
Issuance of Common Stock
  
 1 
    
 10 
    
 40 
                      
 50 
Common Stock Dividends
                    
 (456)
          
 (2)
    
 (458)
Other Changes in Equity
              
 3 
                      
 3 
Net Income
                    
 751 
          
 2 
    
 753 
Other Comprehensive Loss
                          
 (5)
          
 (5)
TOTAL EQUITY – JUNE 30, 2012
  
 505 
  
$
 3,284 
  
$
 6,013 
  
$
 6,185 
  
$
 (475)
  
$
 1 
  
$
 15,008 
                                         
TOTAL EQUITY – DECEMBER 31, 2012
  
 506 
  
$
 3,289 
  
$
 6,049 
  
$
 6,236 
  
$
 (337)
  
$
 - 
  
$
 15,237 
                                         
Issuance of Common Stock
  
 1 
    
 7 
    
 34 
                      
 41 
Common Stock Dividends
                    
 (467)
          
 (2)
    
 (469)
Other Changes in Equity
              
 1 
                      
 1 
Net Income
                    
 701 
          
 2 
    
 703 
Other Comprehensive Income
                          
 24 
          
 24 
TOTAL EQUITY – JUNE 30, 2013
  
 507 
  
$
 3,296 
  
$
 6,084 
  
$
 6,470 
  
$
 (313)
  
$
 - 
  
$
 15,537 
                                         
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 37.

 
33
 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2013 and December 31, 2012
(in millions)
(Unaudited)
 
               
June 30,
  
December 31,
   
2013 
  
2012 
CURRENT ASSETS
            
Cash and Cash Equivalents
  
$
 117 
  
$
 279 
Other Temporary Investments
            
 
(June 30, 2013 and December 31, 2012 Amounts Include $281 and $311, Respectively, Related to Transition Funding and EIS)
    
 298 
    
 324 
Accounts Receivable:
            
 
Customers
    
 725 
    
 685 
 
Accrued Unbilled Revenues
    
 95 
    
 195 
 
Pledged Accounts Receivable – AEP Credit
    
 975 
    
 856 
 
Miscellaneous
    
 174 
    
 171 
 
Allowance for Uncollectible Accounts
    
 (38)
    
 (36)
   
Total Accounts Receivable
    
 1,931 
    
 1,871 
Fuel
    
 879 
    
 844 
Materials and Supplies
    
 695 
    
 675 
Risk Management Assets
    
 187 
    
 191 
Regulatory Asset for Under-Recovered Fuel Costs
    
 98 
    
 88 
Margin Deposits
    
 80 
    
 76 
Prepayments and Other Current Assets
    
 337 
    
 241 
TOTAL CURRENT ASSETS
    
 4,622 
    
 4,589 
             
PROPERTY, PLANT AND EQUIPMENT
            
Electric:
            
 
Generation
    
 26,183 
    
 26,279 
 
Transmission
    
 10,081 
    
 9,846 
 
Distribution
    
 15,887 
    
 15,565 
Other Property, Plant and Equipment (Including Nuclear Fuel and Coal Mining)
    
 4,033 
    
 3,945 
Construction Work in Progress
    
 2,173 
    
 1,819 
Total Property, Plant and Equipment
    
 58,357 
    
 57,454 
Accumulated Depreciation and Amortization
    
 18,932 
    
 18,691 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    
 39,425 
    
 38,763 
             
OTHER NONCURRENT ASSETS
            
Regulatory Assets
    
 5,139 
    
 5,106 
Securitized Transition Assets
    
 2,013 
    
 2,117 
Spent Nuclear Fuel and Decommissioning Trusts
    
 1,791 
    
 1,706 
Goodwill
    
 91 
    
 91 
Long-term Risk Management Assets
    
 317 
    
 368 
Deferred Charges and Other Noncurrent Assets
    
 1,581 
    
 1,627 
TOTAL OTHER NONCURRENT ASSETS
    
 10,932 
    
 11,015 
             
TOTAL ASSETS
  
$
 54,979 
  
$
 54,367 
             
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 37.
                         
                         
                         
                         
                         
                         
 
 
34
 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2013 and December 31, 2012
(dollars in millions)
(Unaudited)
 
               
June 30,
  
December 31,
   
2013 
  
2012 
CURRENT LIABILITIES
            
Accounts Payable
  
$
 987 
  
$
 1,169 
Short-term Debt:
            
 
Securitized Debt for Receivables - AEP Credit
      
 688 
    
 657 
 
Other Short-term Debt
      
 850 
    
 324 
   
Total Short-term Debt
      
 1,538 
    
 981 
Long-term Debt Due Within One Year
            
 
(June 30, 2013 and December 31, 2012 Amounts Include $396 and $367, Respectively, Related to Transition Funding, DCC Fuel and Sabine)
    
 1,819 
    
 2,171 
Risk Management Liabilities
    
 111 
    
 155 
Customer Deposits
    
 297 
    
 316 
Accrued Taxes
    
 680 
    
 747 
Accrued Interest
    
 254 
    
 269 
Regulatory Liability for Over-Recovered Fuel Costs
    
 10 
    
 47 
Other Current Liabilities
    
 823 
    
 968 
TOTAL CURRENT LIABILITIES
    
 6,519 
    
 6,823 
             
NONCURRENT LIABILITIES
            
Long-term Debt
            
 
(June 30, 2013 and December 31, 2012 Amounts Include $2,105 and $2,227, Respectively, Related to Transition Funding, DCC Fuel and Sabine)
    
 15,799 
    
 15,586 
Long-term Risk Management Liabilities
    
 181 
    
 214 
Deferred Income Taxes
    
 9,691 
    
 9,252 
Regulatory Liabilities and Deferred Investment Tax Credits
    
 3,585 
    
 3,544 
Asset Retirement Obligations
    
 1,734 
    
 1,696 
Employee Benefits and Pension Obligations
    
 1,044 
    
 1,075 
Deferred Credits and Other Noncurrent Liabilities
    
 889 
    
 940 
TOTAL NONCURRENT LIABILITIES
    
 32,923 
    
 32,307 
             
TOTAL LIABILITIES
    
 39,442 
    
 39,130 
             
Rate Matters (Note 3)
            
Commitments and Contingencies (Note 4)
            
             
EQUITY
            
Common Stock – Par Value – $6.50 Per Share:
            
     
2013 
  
2012 
              
 
Shares Authorized
600,000,000 
  
600,000,000 
              
 
Shares Issued
507,071,824 
  
506,004,962 
              
(20,336,592 Shares were Held in Treasury as of June 30, 2013 and December 31, 2012)
    
 3,296 
    
 3,289 
Paid-in Capital
    
 6,084 
    
 6,049 
Retained Earnings
    
 6,470 
    
 6,236 
Accumulated Other Comprehensive Income (Loss)
    
 (313)
    
 (337)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY
    
 15,537 
    
 15,237 
             
Noncontrolling Interests
    
 - 
    
 - 
             
TOTAL EQUITY
    
 15,537 
    
 15,237 
             
TOTAL LIABILITIES AND EQUITY
  
$
 54,979 
  
$
 54,367 
             
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 37.

 
35
 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2013 and 2012
(in millions)
(Unaudited)
 
       
Six Months Ended June 30,
   
2013 
  
2012 
OPERATING ACTIVITIES
            
Net Income
  
$
 703 
  
$
 753 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
            
 
Depreciation and Amortization
    
 863 
    
 883 
 
Deferred Income Taxes
    
 367 
    
 417 
 
Asset Impairments and Other Related Charges
    
 154 
    
 - 
 
Carrying Costs Income
    
 (12)
    
 (31)
 
Allowance for Equity Funds Used During Construction
    
 (32)
    
 (47)
 
Mark-to-Market of Risk Management Contracts
    
 16 
    
 8 
 
Amortization of Nuclear Fuel
    
 63 
    
 64 
 
Property Taxes
    
 68 
    
 68 
 
Fuel Over/Under-Recovery, Net
    
 (4)
    
 91 
 
Deferral of Ohio Capacity Costs, Net
    
 (102)
    
 - 
 
Change in Other Noncurrent Assets
    
 (20)
    
 (80)
 
Change in Other Noncurrent Liabilities
    
 12 
    
 31 
 
Changes in Certain Components of Working Capital:
            
   
Accounts Receivable, Net
    
 (53)
    
 93 
   
Fuel, Materials and Supplies
    
 (61)
    
 (199)
   
Accounts Payable
    
 (57)
    
 (100)
   
Accrued Taxes, Net
    
 (214)
    
 (92)
   
Other Current Assets
    
 (10)
    
 (7)
   
Other Current Liabilities
    
 (165)
    
 (139)
Net Cash Flows from Operating Activities
    
 1,516 
    
 1,713 
             
INVESTING ACTIVITIES
            
Construction Expenditures
    
 (1,637)
    
 (1,371)
Change in Other Temporary Investments, Net
    
 38 
    
 (1)
Purchases of Investment Securities
    
 (423)
    
 (546)
Sales of Investment Securities
    
 385 
    
 517 
Acquisitions of Nuclear Fuel
    
 (59)
    
 (11)
Acquisitions of Assets/Businesses
    
 (4)
    
 (88)
Insurance Proceeds Related to Cook Plant Fire
    
 72 
    
 - 
Proceeds from Sales of Assets
    
 11 
    
 8 
Other Investing Activities
    
 (26)
    
 (38)
Net Cash Flows Used for Investing Activities
    
 (1,643)
    
 (1,530)
             
FINANCING ACTIVITIES
            
Issuance of Common Stock, Net
    
 41 
    
 50 
Issuance of Long-term Debt
    
 941 
    
 1,261 
Commercial Paper and Credit Facility Borrowings
    
 17 
    
 21 
Change in Short-term Debt, Net
    
 560 
    
 (425)
Retirement of Long-term Debt
    
 (1,073)
    
 (487)
Commercial Paper and Credit Facility Repayments
    
 (20)
    
 (38)
Principal Payments for Capital Lease Obligations
    
 (33)
    
 (36)
Dividends Paid on Common Stock
    
 (469)
    
 (458)
Other Financing Activities
    
 1 
    
 5 
Net Cash Flows Used for Financing Activities
    
 (35)
    
 (107)
             
Net Increase (Decrease) in Cash and Cash Equivalents
    
 (162)
    
 76 
Cash and Cash Equivalents at Beginning of Period
    
 279 
    
 221 
Cash and Cash Equivalents at End of Period
  
$
 117 
  
$
 297 
             
SUPPLEMENTARY INFORMATION
            
Cash Paid for Interest, Net of Capitalized Amounts
  
$
 455 
  
$
 444 
Net Cash Paid (Received) for Income Taxes
    
 (10)
    
 (42)
Noncash Acquisitions Under Capital Leases
    
 31 
    
 33 
Construction Expenditures Included in Current Liabilities as of June 30,
    
 297 
    
 255 
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,
    
 41 
    
 - 
Noncash Assumption of Liabilities Related to Acquisitions
    
 - 
    
 56 
             
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 37.

 
36
 

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

 
Page
 
Number
   
Significant Accounting Matters
   38
Comprehensive Income
   39
Rate Matters
   43
Commitments, Guarantees and Contingencies
   53
Acquisition and Impairment
   56
Benefit Plans
   57
Business Segments
   58
Derivatives and Hedging
   60
Fair Value Measurements
   67
Income Taxes
   76
Financing Activities
   77
Variable Interest Entities
   80
Sustainable Cost Reductions
   84

 
37
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
1.  SIGNIFICANT ACCOUNTING MATTERS

General

The unaudited condensed consolidated financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC.  Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods.  Net income for the three and six months ended June 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013.  The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2012 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 26, 2013.

Earnings Per Share (EPS)

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

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

     
Three Months Ended June 30,
     
2013 
  
2012 
     
(in millions, except per share data)
           
$/share
        
$/share
Earnings Attributable to AEP Common Shareholders
  
$
 338 
        
$
 362 
      
                           
Weighted Average Number of Basic Shares Outstanding
    
 486.3 
  
$
 0.69 
    
 484.5 
  
$
 0.75 
Weighted Average Dilutive Effect of:
                        
 
Stock Options
    
 - 
    
 - 
    
 0.1 
    
 - 
 
Restricted Stock Units
    
 0.5 
    
 - 
    
 0.3 
    
 - 
Weighted Average Number of Diluted Shares Outstanding
    
 486.8 
  
$
 0.69 
    
 484.9 
  
$
 0.75 

     
Six Months Ended June 30,
     
2013 
  
2012 
     
(in millions, except per share data)
           
$/share
        
$/share
Earnings Attributable to AEP Common Shareholders
  
$
 701 
        
$
 751 
      
                           
Weighted Average Number of Basic Shares Outstanding
    
 486.1 
  
$
 1.44 
    
 484.2 
  
$
 1.55 
Weighted Average Dilutive Effect of:
                        
 
Stock Options
    
 - 
    
 - 
    
 0.1 
    
 - 
 
Restricted Stock Units
    
 0.5 
    
 - 
    
 0.3 
    
 - 
Weighted Average Number of Diluted Shares Outstanding
    
 486.6 
  
$
 1.44 
    
 484.6 
  
$
 1.55 

There were no antidilutive shares outstanding as of June 30, 2013 and 2012.
 
38
 

2.  COMPREHENSIVE INCOME

Presentation of Comprehensive Income

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

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2013
 
     
Cash Flow Hedges
                  
           
Interest Rate and
  
Securities
  
Pension
      
     
Commodity
  
Foreign Currency
  
Available for Sale
  
and OPEB
  
Total
     
(in millions)
Balance in AOCI as of March 31, 2013
$
 12 
  
$
 (26)
  
$
 5 
  
$
 (297)
  
$
 (306)
Change in Fair Value Recognized in AOCI
  
 (8)
    
 (1)
    
 - 
    
 - 
    
 (9)
Amounts Reclassified from AOCI
  
 (3)
    
 2 
    
 - 
    
 3 
    
 2 
Net Current Period Other
                            
   
Comprehensive Income
  
 (11)
    
 1 
    
 - 
    
 3 
    
 (7)
Balance in AOCI as of June 30, 2013
$
 1 
  
$
 (25)
  
$
 5 
  
$
 (294)
  
$
 (313)

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2013
 
     
Cash Flow Hedges
                  
           
Interest Rate and
  
Securities
  
Pension
      
     
Commodity
  
Foreign Currency
  
Available for Sale
  
and OPEB
  
Total
     
(in millions)
Balance in AOCI as of December 31, 2012
$
 (8)
  
$
 (30)
  
$
 4 
  
$
 (303)
  
$
 (337)
Change in Fair Value Recognized in AOCI
  
 10 
    
 2 
    
 1 
    
 - 
    
 13 
Amounts Reclassified from AOCI
  
 (1)
    
 3 
    
 - 
    
 9 
    
 11 
Net Current Period Other
                            
   
Comprehensive Income
  
 9 
    
 5 
    
 1 
    
 9 
    
 24 
Balance in AOCI as of June 30, 2013
$
 1 
  
$
 (25)
  
$
 5 
  
$
 (294)
  
$
 (313)

 
39
 
Reclassifications Out of Accumulated Other Comprehensive Income

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

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended June 30, 2013
           
       
Amount of
       
(Gain) Loss
       
Reclassified
       
from AOCI
Gains and Losses on Cash Flow Hedges
  
(in millions)
Commodity:
      
   
Utility Operations Revenues
  
$
 - 
   
Other Revenues
    
 (2)
   
Purchased Electricity for Resale
    
 (2)
   
Property, Plant and Equipment
    
 - 
   
Regulatory Assets (a)
    
 - 
Subtotal - Commodity
    
 (4)
           
Interest Rate and Foreign Currency:
      
   
Interest Expense
    
 2 
Subtotal - Interest Rate and Foreign Currency
    
 2 
           
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 (2)
Income Tax (Expense) Credit
    
 (1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 (1)
       
Gains and Losses on Available-for-Sale Securities
      
Interest Income
    
 - 
Interest Expense
    
 - 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 - 
Income Tax (Expense) Credit
    
 - 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 - 
         
Amortization of Pension and OPEB
      
Prior Service Cost (Credit)
    
 (4)
Actuarial (Gains)/Losses
    
 9 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 5 
Income Tax (Expense) Credit
    
 2 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 3 
           
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
  
$
 2 

 
40
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Six Months Ended June 30, 2013
           
       
Amount of
       
(Gain) Loss
       
Reclassified
       
from AOCI
Gains and Losses on Cash Flow Hedges
  
(in millions)
Commodity:
      
   
Utility Operations Revenues
  
$
 - 
   
Other Revenues
    
 (5)
   
Purchased Electricity for Resale
    
 4 
   
Property, Plant and Equipment
    
 - 
   
Regulatory Assets (a)
    
 - 
Subtotal - Commodity
    
 (1)
           
Interest Rate and Foreign Currency:
      
   
Interest Expense
    
 4 
Subtotal - Interest Rate and Foreign Currency
    
 4 
           
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 3 
Income Tax (Expense) Credit
    
 1 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 2 
       
Gains and Losses on Available-for-Sale Securities
      
Interest Income
    
 - 
Interest Expense
    
 - 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 - 
Income Tax (Expense) Credit
    
 - 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 - 
         
Amortization of Pension and OPEB
      
Prior Service Cost (Credit)
    
 (9)
Actuarial (Gains)/Losses
    
 23 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 14 
Income Tax (Expense) Credit
    
 5 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 9 
           
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
  
$
 11 

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

 
41
 
The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2012.  All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2012
             
Interest Rate
      
             
and Foreign
      
       
Commodity
  
Currency
  
Total
       
(in millions)
Balance in AOCI as of March 31, 2012
  
$
 (16)
  
$
 (18)
  
$
 (34)
Changes in Fair Value Recognized in AOCI
    
 (3)
    
 (13)
    
 (16)
Amount of (Gain) or Loss Reclassified from AOCI
                  
 
to Statement of Income/within Balance Sheet:
                  
   
Utility Operations Revenues
    
 - 
    
 - 
    
 - 
   
Other Revenues
    
 (2)
    
 - 
    
 (2)
   
Purchased Electricity for Resale
    
 6 
    
 - 
    
 6 
   
Interest Expense
    
 - 
    
 1 
    
 1 
   
Regulatory Assets (a)
    
 1 
    
 - 
    
 1 
Balance in AOCI as of June 30, 2012
  
$
 (14)
  
$
 (30)
  
$
 (44)

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

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

 
42
 
The following tables provide details of changes in unrealized gains and losses related to Securities Available for Sale and the reasons for changes for the three and six months ended June 30, 2012.  All amounts in the following tables are presented net of related income taxes.

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

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

3.  RATE MATTERS

As discussed in the 2012 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within our 2012 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition.  The following discusses ratemaking developments in 2013 and updates the 2012 Annual Report.
 
Regulatory Assets Not Yet Being Recovered
       
June 30,
  
December 31,
       
2013 
  
2012 
       
(in millions)
Noncurrent Regulatory Assets
            
Regulatory assets not yet being recovered pending future proceedings:
            
                 
Regulatory Assets Currently Earning a Return
            
 
Storm Related Costs
  
$
 22 
  
$
 23 
 
Economic Development Rider
    
 14 
    
 13 
 
Other Regulatory Assets Not Yet Being Recovered
    
 3 
    
 1 
Regulatory Assets Currently Not Earning a Return
            
 
Storm Related Costs
    
 142 
    
 172 
 
Virginia Environmental Rate Adjustment Clause
    
 29 
    
 29 
 
Ormet Delayed Payment Arrangement
    
 20 
    
 5 
 
Mountaineer Carbon Capture and Storage Product Validation Facility
    
 14 
    
 14 
 
Litigation Settlement
    
 - 
    
 11 
 
Other Regulatory Assets Not Yet Being Recovered
    
 44 
    
 36 
Total Regulatory Assets Not Yet Being Recovered
  
$
 288 
  
$
 304 

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

 
43
 
OPCo Rate Matters

Ohio Electric Security Plan Filing

2009 – 2011 ESP

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

In October 2011, the PUCO issued an order in the remand proceeding.  As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011.  In February 2012, the Ohio Consumers’ Counsel and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance.  As of June 30, 2013, OPCo’s net deferred fuel balance was $484 million, excluding unrecognized equity carrying costs.  A decision from the Supreme Court of Ohio is pending.

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off in 2010 and a subsequent refund to customers during 2011.  The IEU and the Ohio Energy Group filed appeals with the Supreme Court of Ohio challenging the PUCO’s SEET decision.  In December 2012, the Supreme Court of Ohio issued an order which rejected all of the intervenors’ challenges and affirmed the PUCO decision.

The 2009 SEET order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm.  In January 2013, the PUCO found there was not a need for the large solar farm.  The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project by the end of 2013.  Management continues to evaluate other investment alternatives.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings, which included off-system sales in the SEET calculation.  In December 2011, the PUCO staff filed testimony that recommended a $23 million refund of 2010 earnings.  OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO-ordered SEET refund.  OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis.  The PUCO approved OPCo’s requests to file the SEET for 2011 and 2012 one month after the PUCO issues an order on the 2010 SEET.  Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in 2012 for OPCo.  Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo.

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover deferred fuel costs in rates beginning September 2012.  The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin.  In November 2012, OPCo filed an appeal at the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate.  The IEU and the Ohio Consumers’ Counsel also filed appeals at the Supreme Court of Ohio in November 2012 arguing that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues and reduced carrying costs due to an accumulated deferred income tax credit.  These appeals could reduce OPCo’s net deferred fuel balance up to the total balance, which could reduce future net income and cash flows.  A decision from the Supreme Court of Ohio is pending.

Management is unable to predict the outcome of the unresolved litigation discussed above.  Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition.
 
44
 

June 2012 – May 2015 ESP Including Capacity Charge

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

As part of the ESP decision, the PUCO ordered OPCo to conduct an energy-only auction for 10% of the SSO load with delivery beginning six months after the receipt of final orders in both the ESP and corporate separation cases and extending through May 2015.  The initiation of the auction is pending the issuance of an order by the PUCO in a separate docket.  The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning June 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015.  OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The RPM price is approximately $33/MW day through May 2014.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.  As of June 30, 2013,  OPCo’s incurred deferred capacity costs balance of $171 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR is expected to provide approximately $500 million of revenue over the ESP period and will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs.  In August 2012, the IEU filed an action with the Supreme Court of Ohio stating, among other things, that OPCo’s collection of its capacity costs is illegal.  In April 2013, the Supreme Court of Ohio dismissed the IEU’s action.

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

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).  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. 

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

Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets at net book value to AEPGenCo.  AEPGenCo will also assume the associated generation liabilities.  In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.
 
45
 

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

Storm Damage Recovery Rider (SDRR)

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

2009 Fuel Adjustment Clause Audit

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

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

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes.  As of June 30, 2013, the amount of OPCo’s carrying costs that could potentially be reduced due to the accumulated income tax issue is estimated to be $34 million, including $18 million of unrecognized equity carrying costs.  These amounts include the carrying costs exposure of the 2009 FAC audit, which has been appealed by an intervenor to the Supreme Court of Ohio.  Decisions from the PUCO are pending.  Management is unable to predict the outcome of these proceedings.  If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet.  This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009.  In March 2009, the PUCO approved a FAC in the ESP filing and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio.  The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record a regulatory asset for the difference between the approved market price and the rate paid by Ormet.  Through
 
 
46
 
September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs.  In November 2009, OPCo requested that the PUCO approve recovery of the deferral under the interim agreement plus a weighted average cost of capital carrying charge.  The deferral amount is included in OPCo’s FAC phase-in deferral balance.  In the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related regulatory asset and requested that the PUCO prevent OPCo from collecting the Ormet-related revenues in the future.  The PUCO did not take any action on this request.  The intervenors raised the issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.  This issue remains pending before the PUCO.  If OPCo is not ultimately permitted to fully recover its requested deferrals under the interim arrangement, it could reduce future net income and cash flows and impact financial condition.

Special Rate Mechanism for Ormet

In October 2012, the PUCO issued an order approving a delayed payment plan for Ormet’s October and November 2012 power billings totaling $27 million to be paid in equal monthly installments over the period January 2014 to May 2015 without interest.  In the event Ormet does not pay its $27 million obligation, the PUCO permitted OPCo to recover the unpaid balance, up to $20 million, in the economic development rider.  To the extent unpaid amounts exceed $20 million, it could reduce future net income and cash flows and impact financial condition.

In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware but is current on all payments due to OPCo.  In June 2013, Ormet filed a motion with the PUCO to amend its contract with OPCo which currently provides for services through 2018.  The proposed amendments would allow Ormet to purchase power from a third party beginning January 2014.  In July 2013, OPCo filed its objections with the PUCO which included a recommendation to have Ormet pay an exit fee as a potential resolution to address the financial concerns associated with amending the current contract.  Hearings at the PUCO are scheduled for August 2013.  As of June 30, 2013, OPCo has a regulatory asset of $20 million and a net receivable of $6 million recorded related to the special rate mechanism for Ormet.

Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  As of June 30, 2013, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order.  Intervenors have filed motions with the PUCO requesting OPCo refund all collected pre-construction costs to Ohio ratepayers with interest.

Management cannot predict the outcome of these proceedings concerning the Ohio IGCC plant or what effect, if any, these proceedings could have on future net income and cash flows.  However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.  As of June 30, 2013, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital cost cap, SWEPCo has capitalized approximately $1.8 billion of expenditures, including AFUDC and capitalized interest of $328 million and related transmission costs of $118 million.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%).  Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN.  In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN.  The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the SPP market.
 
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The PUCT approved a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers.  SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful.  The Texas Industrial Energy Consumers (TIEC) filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers.  The Texas District Court and the Texas Court of Appeals affirmed the PUCT’s order in all respects.  In April 2012, SWEPCo and the TIEC filed petitions for review at the Supreme Court of Texas, which were denied in March 2013.  In April 2013, SWEPCo and the TIEC filed motions for rehearing at the Supreme Court of Texas.  In May 2013, the Supreme Court of Texas requested the PUCT and the TIEC respond to SWEPCo’s motion.

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.
 
2012 Texas Base Rate Case
 
In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million, primarily due to the Turk Plant, based upon an 11.25% return on common equity to be effective January 2013.  The requested base rate increase included a return on and of the Texas jurisdictional share (approximately 33%) of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs.  The filing also (a) increased depreciation expense due to the decrease in the average remaining life of the Welsh Plant to account for the change in the retirement date of the Welsh Plant, Unit 2 from 2040 to 2016, (b) proposed increased vegetation management expenditures and (c) included a return on and of the Stall Unit as of December 2011 and associated operation and maintenance costs.

In September 2012, an Administrative Law Judge (ALJ) issued an order that granted the establishment of SWEPCo’s existing rates as temporary rates beginning in late January 2013, subject to true-up to the final PUCT-approved rates.

In December 2012, several intervenors, including the PUCT staff, filed testimony that recommended an annual base rate increase between $16 million and $51 million based upon a return on common equity between 9% and 9.55%.  In addition, two intervenors recommended that the Turk Plant be excluded from rate base.  In May 2013, the ALJ issued a proposal for decision (PFD) and added clarifications in July 2013.  The PFD, as clarified, made various recommendations including (a) an annual base rate increase of approximately $41 million based upon a return on common equity of 9.65%, (b) the disallowance of the Turk Plant capital costs in excess of the investment and committed costs as of June 2010 plus the cost to retrofit Welsh Plant, Unit 2 which, as of June 30, 2013, SWEPCo estimates could result in a write-off of approximately $74 million (in excess of the $62 million reserve previously recorded related to the Texas capital cost cap) and (c) the exclusion, until SWEPCo’s next Texas base rate case, of the Turk Plant transmission line investment that was not in service at the end of the test year.  A decision from the PUCT is expected in the third quarter of 2013.  If the PUCT does not approve full cost recovery of SWEPCo’s Texas jurisdictional share of assets, it could reduce future net income and cash flows and impact financial condition.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant.  In February 2013, a settlement was filed and approved by the LPSC.  The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually.  The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund based on the staff review of the cost of service and the prudence review of the Turk Plant.  The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover all non-fuel Turk Plant costs and a full weighted-average cost of capital return on the Turk Plant portion of 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.
 
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Flint Creek Plant Environmental Controls

In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA.  The estimated cost of the project is $408 million, excluding AFUDC and company overheads.  As a joint owner of the Flint Creek Plant, SWEPCo’s portion of those costs is estimated at $204 million.  As of June 30, 2013, SWEPCo has incurred $24 million related to this project, including AFUDC and company overheads.  In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant.

APCo and WPCo Rate Matters

Plant Transfers

In October 2012, the AEP East Companies submitted several filings with the FERC regarding the transfer of certain generation plants within the AEP System.  See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.  In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant, comprising 1,647 MW of average annual generating capacity presently owned by OPCo.  In April 2013, several intervenors filed testimony with the Virginia SCC and made recommendations relating to APCo’s proposed asset transfers including the issuance of a Request for Proposal (RFP) for APCo’s resource needs.  In May 2013, Virginia SCC staff filed testimony making recommendations including several alternatives to the asset transfers as proposed including the recommendation to approve only the Amos Plant, Unit 3 asset transfer and limiting the non-contractual liabilities to be assumed by APCo.  Hearings were held at the Virginia SCC in June 2013.  In June 2013, intervenors filed testimony with the WVPSC and made recommendations relating to APCo’s proposed asset transfers including the transfer of only one plant, the issuance of a RFP for any additional capacity and energy requirements and limiting the liabilities to the types and amounts reflected in the net book value of the asset transfers.  Hearings were held at the WVPSC in July 2013.  APCo is currently pursuing cost recovery of these plants in West Virginia and plans to pursue cost recovery in Virginia.  If APCo and WPCo are not ultimately permitted to recover their incurred costs, it could reduce future net income and cash flows and impact financial condition.

APCo IGCC Plant

As of June 30, 2013, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $10 million applicable to its Virginia jurisdiction.  If the costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs effective February 2014 over a one-year period.  In March 2013, the environmental RAC surcharge expired related to the collection of 2009 and 2010 environmental compliance costs.  APCo has deferred $28 million as of June 30, 2013 for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $11 million of unrecognized equity carrying costs.  Hearings at the Virginia SCC are scheduled for August 2013.  If the Virginia SCC were to disallow any portion of the environmental RAC, it could reduce future net income and cash flows.

2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing

In March 2013, APCo filed with the Virginia SCC for an increase in its generation RAC revenues of $12 million for a total of $38 million annually to collect costs related to the Dresden Plant.  The generation RAC increase is expected to be effective in March 2014.  APCo has deferred $4 million as of June 30, 2013 for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $4 million of unrecognized equity carrying costs.  Hearings at the Virginia SCC are scheduled for August 2013.  If the Virginia SCC were to disallow any portion of the generation RAC, it could reduce future net income and cash flows.
 
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2012 West Virginia Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation which allows the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred ENEC balances and other ENEC-related assets.  In August 2012, APCo and WPCo filed a request with the WVPSC for a financing order to securitize a total of $422 million related to the December 2011 under-recovered ENEC deferral balance including other ENEC-related assets of $13 million and related future financing costs of $7 million.  Upon completion of the securitization, APCo would offset its current ENEC rates by an amount to recover the securitized balance over the securitization period.  In March 2013, APCo, WPCo and intervenors filed a settlement agreement with the WVPSC which recommended the WVPSC authorize APCo to securitize $376 million plus upfront financing costs.  Hearings at the WVPSC on the securitization are scheduled for July 2013.  As of June 30, 2013, APCo’s ENEC under-recovery balance of $287 million, net of 2012 and 2013 over-recovery, was recorded in Regulatory Assets on the balance sheet, excluding $3 million of unrecognized equity carrying costs and $15 million of other ENEC-related assets.

In April 2013, APCo and WPCo filed to keep total rates unchanged with a portion of the ENEC to be specifically identified for the amount to be securitized in accordance with the proposed securitization settlement agreement.  The remaining ENEC rate is proposed to include (a) the proposed transfer of certain generation facilities from OPCo and the APCo/WPCo merger, (b) construction surcharges and (c) ongoing ENEC costs.  Management is currently reviewing intervenor testimony filed in July 2013 that recommends lower ENEC revenues.  Hearings at the WVPSC are scheduled for August 2013.  If the WVPSC were to disallow any portion of the ENEC, it could reduce future net income and cash flows.

Virginia Storm Costs

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

PSO Rate Matters

Oklahoma Environmental Compliance Plan

In September 2012, based upon an agreement with the Federal EPA, the State of Oklahoma and other parties, 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.  The plan requested approval for (a) an estimated $210 million of new environmental investment, excluding AFUDC and overheads of $46 million, that will be incurred prior to 2016 at NES Unit 3, (b) accelerated recovery through 2026 of the net book value of NES Units 3 and 4 (combined net book value of the two units is $231 million as of June 30, 2013), (c) an estimated $83 million of new investment incurred through 2016 at various gas units and (d) a new 15-year purchase power agreement (PPA) with a nonaffiliated entity, effective in 2016, with cost recovery through a rider, including an annual earnings component of $3 million.  Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery in a future rate proceeding.

In January 2013, testimony filed by the OCC staff and the Oklahoma Office of the Attorney General (OOAG) recommended no earnings component on the PPA and to delay final decisions until 2020 on parts of the plan including cost recovery of the net book value of NES Unit 3 and any increases in fuel costs due to reductions in the output of energy from NES Unit 3 beginning in 2021.  The testimony recommended that cost recovery could extend past 2026 on parts of the plan and recommended a $175 million cost cap on NES Unit 3 environmental investment, excluding AFUDC and overheads.

In March 2013, the OCC staff and the OOAG filed additional testimony revising the recommended cost cap on NES Unit 3 to $210 million, excluding AFUDC and overheads, and recommended conditional approval of the planned NES Unit 3 retirement subject to OCC approval in 2020 provided the planned retirement is consistent with environmental rules at that time.
 
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Also, an intervenor representing some of PSO’s large industrial users opposed the majority of PSO’s plan, including recommending no cost recovery of NES Units 3 and 4 book value amounts not recovered at the time of their retirement and no recovery of the PPA costs, including earnings on the PPA.  In February 2013, the OCC staff requested a stay in this proceeding, which was granted by the OCC in March 2013.  In July 2013, the OCC staff filed a motion to lift the stay and dismiss PSO’s environmental compliance plan case without prejudice.  A hearing on the motion will be held in August 2013.  If this case is dismissed, PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan.

If PSO is ultimately not permitted to fully recover its net book value of NES Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%.  In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates from $85 million to $92 million.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed a request for reconsideration with the IURC, which was denied.  Also in March 2013, the OUCC filed an appeal of the order with the Indiana Court of Appeals.  If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of June 30, 2013, I&M has incurred $240 million related to the LCM Project, including AFUDC.

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

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.  If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

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 of its units at the Rockport Plant with a Dry Sorbent Injection system.  The estimated cost in the application was $285 million, excluding AFUDC.  The application requested deferral treatment of any unrecovered carrying costs incurred during construction and incremental post in-service depreciation expense and operation and maintenance expenses until such costs are recognized and recovered in a rider.  I&M also requested cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism.
 
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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 direct ownership share.  The settlement agreement specifies that 80% of the recoverable I&M direct ownership share of CCT Project costs will be recovered through a Federal Mandate Rider with the remaining 20% deferred until rates are established in a subsequent rate case.  If the IURC approves the settlement agreement, I&M’s Indiana allocated share of the CCT Project costs received in the form of purchased power from AEGCo will be recovered in subsequent I&M rate cases.  Hearings at the IURC are scheduled for August 2013.  A decision is expected by November 2013.  As of June 30, 2013, we have incurred costs of $77 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.

KPCo Rate Matters

Plant Transfer

In October 2012, the AEP East Companies submitted several filings with the FERC.  See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.  In December 2012, KPCo filed a request with the KPSC for approval to transfer at net book value to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by OPCo.  KPCo also requested costs related to the Big Sandy Plant, Unit 2 FGD project be established as a regulatory asset.  KPCo is currently seeking recovery of these costs with the KPSC.  In March 2013, KPCo issued a Request for Proposal (RFP) to purchase up to 250 MW of long-term capacity and energy to replace the capacity from the retirement of Big Sandy Plant, Unit 1.  In June 2013, KPCo filed the results of its RFP with the KPSC.  As of June 30, 2013, KPCo has incurred $28 million related to the FGD project, which is recorded in Deferred Charges and Other Noncurrent Assets on the balance sheet.

In May 2013, a memorandum of understanding (MOU) between KPCo, KIUC and the Sierra Club was filed with the KPSC.  The MOU includes (a) the transfer of a one-half interest in the Mitchell Plant to KPCo at net book value on December 31, 2013 (b) the implementation of an Asset Transfer Rider to collect $44 million annually effective January 2014, subject to true-up, (c) the authorization to record FGD project costs as a regulatory asset, (d) the conversion of Big Sandy Plant, Unit 1 to natural gas and (e) any off-system sales margins above the $15.3 million annual level in base rates be retained by KPCo.  In July 2013, KPCo, KIUC and the Sierra Club filed a settlement agreement with the KPSC pursuant to the MOU as modified.  The settlement agreement also addressed potential greenhouse gas initiatives on the Mitchell Plant.  The Attorney General was not a party to the settlement agreement.  If approved, KPCo will withdraw the current base rate case request and current rates will remain in effect until at least May 2015.  Hearings were held at the KPSC in July 2013.  If KPCo is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows and impact financial condition.

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) and cost recovery of Big Sandy Plant, Units 1 and 2.  The filing also includes requests for recovery of deferrals totaling $48 million including $28 million related to the Big Sandy Plant FGD project and $12 million related to 2012 storm costs which are recorded in Deferred Charges and Other Noncurrent Assets and Regulatory Assets, respectively, on the balance sheet.  Additionally, KPCo proposed that Big Sandy Plant, Unit 2 expenses incurred over the period January 2014 through May 2015 be deferred and recovered over five years beginning January 2014.  Also in June 2013, a settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club was filed with the KPSC which supported the Mitchell plant transfer discussed above.  If the settlement agreement is approved, KPCo will withdraw this base rate case request and current rates will remain in effect until at least May 2015.  If KPCo is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows and impact financial condition.
 
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FERC Rate Matters

Corporate Separation and Termination of Interconnection Agreement

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

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

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

If 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.

4.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

We are subject to certain claims and legal actions arising in our ordinary course of business.  In addition, our business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation against us cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on our financial statements.  The Commitments, Guarantees and Contingencies note within our 2012 Annual Report should be read in conjunction with this report.

GUARANTEES

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

Letters of Credit

We enter into standby letters of credit with third parties.  As Parent, we issue all of these letters of credit in our ordinary course of business on behalf of our subsidiaries.  These letters of credit cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.
 
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We have two credit facilities totaling $3.5 billion, under which we may issue up to $1.2 billion as letters of credit.  As of June 30, 2013, the maximum future payments for letters of credit issued under the credit facilities were $120 million with maturities ranging from October 2013 to June 2014.

We have $402 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $407 million.  The letters of credit have maturities ranging from March 2014 to March 2015.

Guarantees of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study completed in 2010, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation.  As of June 30, 2013, SWEPCo has collected approximately $62 million through a rider for final mine closure and reclamation costs, of which $12 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $50 million is recorded in Asset Retirement Obligations on our condensed balance sheets.

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

Indemnifications and Other Guarantees

Contracts

We enter into several types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, our exposure generally does not exceed the sale price.  The status of certain sale agreements is discussed in the 2012 Annual Report “Dispositions” section of Note 6.  As of June 30, 2013, there were no material liabilities recorded for any indemnifications.

Master Lease Agreements

We lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, we are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.  As of June 30, 2013, the maximum potential loss for these lease agreements was approximately $20 million assuming the fair value of the equipment is zero at the end of the lease term.

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignment is accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $13 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2013.
 
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Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 83% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  The maximum potential losses related to the guarantee are approximately $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, we believe that the fair value would produce a sufficient sales price to avoid any loss.

ENVIRONMENTAL CONTINGENCIES

Carbon Dioxide Public Nuisance Claims

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing.  An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision.  The petition was denied in January 2011.  Plaintiffs refiled their complaint in federal district court.  The court ordered all defendants to respond to the refiled complaints in October 2011.  In March 2012, the court granted the defendants’ motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations.  In May 2013, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court’s dismissal of the complaint. The plaintiffs may seek further review in the U.S. Supreme Court.  We will continue to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Alaskan Villages’ Claims

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court’s decision, holding that the CAA displaced Kivalina’s claims for damages.  Plaintiffs filed seeking further review in the U.S. Supreme Court.  In May 2013, the U.S. Supreme Court denied the plaintiffs’ request for review.
 
The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation
 
By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, our generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials.  We currently incur costs to dispose of these substances safely.

In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M started remediation work in accordance with a plan approved by MDEQ.  I&M’s reserve is approximately $10 million.  As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ.  We cannot predict the amount of additional cost, if any.
 
55
 

NUCLEAR CONTINGENCIES

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

Nuclear Incident Insurance

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

OPERATIONAL CONTINGENCIES

Natural Gas Markets Lawsuits

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

5.  ACQUISITION AND IMPAIRMENT

ACQUISITION

2012

BlueStar Energy (Generation and Marketing segment)

In March 2012, we completed the acquisition of BlueStar Energy Holdings, Inc. (BlueStar) and its independent retail electric supplier BlueStar Energy Solutions for $70 million.  This transaction also included goodwill of $15 million, intangible assets associated with sales contracts and customer accounts of $58 million and liabilities associated with supply contracts of $25 million.  BlueStar has been in operation since 2002.  Beginning in June 2012, BlueStar began doing business as AEP Energy.  AEP Energy provides electric supply for retail customers in Ohio, Illinois and other deregulated electricity markets and also provides energy solutions throughout the United States, including demand response and energy efficiency services.
 
56
 

IMPAIRMENT

2013

Muskingum River Plant, Unit 5 (Utility Operations segment)

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

6.  BENEFIT PLANS

Components of Net Periodic Benefit Cost

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

     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Three Months Ended June 30,
  
Three Months Ended June 30,
 
2013 
  
2012 
  
2013 
  
2012 
 
(in millions)
Service Cost
$
 18 
  
$
 19 
  
$
 6 
  
$
 11 
Interest Cost
  
 51 
    
 55 
    
 17 
    
 26 
Expected Return on Plan Assets
  
 (70)
    
 (79)
    
 (26)
    
 (25)
Amortization of Prior Service Credit
  
 - 
    
 - 
    
 (18)
    
 (4)
Amortization of Net Actuarial Loss
  
 46 
    
 38 
    
 16 
    
 15 
Net Periodic Benefit Cost (Credit)
$
 45 
  
$
 33 
  
$
 (5)
  
$
 23 

     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Six Months Ended June 30,
  
Six Months Ended June 30,
 
2013 
  
2012 
  
2013 
  
2012 
 
(in millions)
Service Cost
$
 35 
  
$
 38 
  
$
 12 
  
$
 23 
Interest Cost
  
 101 
    
 111 
    
 35 
    
 52 
Expected Return on Plan Assets
  
 (139)
    
 (159)
    
 (53)
    
 (50)
Amortization of Prior Service Cost (Credit)
  
 1 
    
 - 
    
 (35)
    
 (9)
Amortization of Net Actuarial Loss
  
 92 
    
 75 
    
 32 
    
 29 
Net Periodic Benefit Cost (Credit)
$
 90 
  
$
 65 
  
$
 (9)
  
$
 45 

 
57
 
7.  BUSINESS SEGMENTS

As outlined in our 2012 Annual Report, our primary business is the generation, transmission and distribution of electricity.  Within our Utility Operations segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

Our reportable segments and their related business activities are outlined below:

Utility Operations

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

Transmission Operations

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

AEP River Operations

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

Generation and Marketing

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

The remainder of our activities is presented as All Other.  While not considered a reportable segment, All Other includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

 
58
 
The tables below present our reportable segment information for the three and six months ended June 30, 2013 and 2012 and balance sheet information as of June 30, 2013 and December 31, 2012.  These amounts include certain estimates and allocations where necessary.

                       
Nonutility Operations
                  
                             
Generation
                  
     
Utility
    
Transmission
  
AEP River
and
All Other
Reconciling
    
     
Operations
    
Operations
  
Operations
Marketing
(a)
 Adjustments
Consolidated
       
(in millions)
Three Months Ended June 30, 2013
                                              
Revenues from:
                                              
   
External Customers
  
$
 3,246 
    
$
 7 
    
$
 112 
  
$
 214 
  
$
 3 
  
$
 - 
  
$
 3,582 
   
Other Operating Segments
    
 32 
      
 12 
      
 5 
    
 - 
    
 1 
    
 (50)
    
 - 
Total Revenues
  
$
 3,278 
    
$
 19 
    
$
 117 
  
$
 214 
  
$
 4 
  
$
 (50)
  
$
 3,582 
                                                   
Net Income (Loss)
  
$
 222 
    
$
 18 
    
$
 (9)
  
$
 4 
  
$
 104 
  
$
 - 
  
$
 339 
                                                   
                       
Nonutility Operations
                  
                             
Generation
                  
     
Utility
    
Transmission
  
AEP River
and
All Other
Reconciling
    
     
Operations
    
Operations
  
Operations
Marketing
(a)
 Adjustments
Consolidated
       
(in millions)
Three Months Ended June 30, 2012
                                              
Revenues from:
                                              
   
External Customers
  
$
 3,234 
    
$
 1 
    
$
 163 
  
$
 148 
  
$
 5 
  
$
 - 
  
$
 3,551 
   
Other Operating Segments
    
 24 
      
 1 
      
 4 
    
 - 
    
 1 
    
 (30)
    
 - 
Total Revenues
  
$
 3,258 
    
$
 2 
    
$
 167 
  
$
 148 
  
$
 6 
  
$
 (30)
  
$
 3,551 
                                                   
Net Income (Loss)
  
$
 365 
    
$
 8 
    
$
 3 
  
$
 (5)
  
$
 (8)
  
$
 - 
  
$
 363 

                       
Nonutility Operations
                  
                             
Generation
                  
     
Utility
    
Transmission
AEP River
and
All Other
Reconciling
    
     
Operations
    
Operations
Operations
Marketing
(a)
 Adjustments
Consolidated
       
(in millions)
Six Months Ended June 30, 2013
                                              
Revenues from:
                                              
   
External Customers
  
$
 6,732 
    
$
 10 
    
$
 240 
  
$
 420 
  
$
 6 
  
$
 - 
  
$
 7,408 
   
Other Operating Segments
    
 63 
      
 17 
      
 10 
    
 - 
    
 3 
    
 (93)
    
 - 
Total Revenues
  
$
 6,795 
    
$
 27 
    
$
 250 
  
$
 420 
  
$
 9 
  
$
 (93)
  
$
 7,408 
                                                   
Net Income (Loss)
  
$
 571 
    
$
 31 
    
$
 (11)
  
$
 11 
  
$
 101 
  
$
 - 
  
$
 703 
                                                   
                       
Nonutility Operations
                  
                             
Generation
                  
     
Utility
    
Transmission
AEP River
and
All Other
Reconciling
    
     
Operations
    
Operations
Operations
Marketing
(a)
 Adjustments
Consolidated
       
(in millions)
Six Months Ended June 30, 2012
                                              
Revenues from:
                                              
   
External Customers
  
$
 6,596 
    
$
 2 
    
$
 335 
  
$
 233 
  
$
 10 
  
$
 - 
  
$
 7,176 
   
Other Operating Segments
    
 47 
      
 3 
      
 11 
    
 - 
    
 3 
    
 (64)
    
 - 
Total Revenues
  
$
 6,643 
    
$
 5 
    
$
 346 
  
$
 233 
  
$
 13 
  
$
 (64)
  
$
 7,176 
                                                   
Net Income (Loss)
  
$
 749 
    
$
 17 
    
$
 12 
  
$
 (6)
  
$
 (19)
  
$
 - 
  
$
 753 

 
59
 
                     
Nonutility Operations
                    
                           
Generation
        
Reconciling
        
     
Utility
    
Transmission
  
AEP River
  
and
  
All Other
  
 Adjustments
        
     
Operations
    
Operations
  
Operations
  
Marketing
  
(a)
  
(b)
       Consolidated
       
(in millions)
June 30, 2013
                                              
Total Property, Plant and Equipment
  
$
 56,275 
    
$
 1,079 
  
$
 638 
  
$
 626 
  
$
 8 
  
$
 (269)
    
$
 58,357 
Accumulated Depreciation and
                                              
 
Amortization
    
 18,561 
      
 6 
    
 175 
    
 261 
    
 7 
    
 (78)
      
 18,932 
Total Property, Plant and
                                              
 
 Equipment - Net
  
$
 37,714 
    
$
 1,073 
  
$
 463 
  
$
 365 
  
$
 1 
  
$
 (191)
    
$
 39,425 
                                                   
Total Assets
  
$
 51,841 
    
$
 1,588 
  
$
 646 
  
$
 1,017 
  
$
 18,155 
  
$
 (18,268)
(c)
  
$
 54,979 
                                                   
                     
Nonutility Operations
                    
                           
Generation
        
Reconciling
        
     
Utility
    
Transmission
  
AEP River
  
and
  
All Other
  
 Adjustments
        
     
Operations
    
Operations
  
Operations
  
Marketing
  
(a)
  
(b)
       Consolidated
       
(in millions)
December 31, 2012
                                              
Total Property, Plant and Equipment
  
$
 55,707 
    
$
 748 
  
$
 636 
  
$
 621 
  
$
 8 
  
$
 (266)
    
$
 57,454 
Accumulated Depreciation and
                                              
 
 Amortization
    
 18,344 
      
 4 
    
 161 
    
 246 
    
 7 
    
 (71)
      
 18,691 
Total Property, Plant and
                                              
 
 Equipment - Net
  
$
 37,363 
    
$
 744 
  
$
 475 
  
$
 375 
  
$
 1 
  
$
 (195)
    
$
 38,763 
                                                   
Total Assets
  
$
 51,477 
    
$
 1,216 
  
$
 670 
  
$
 1,005 
  
$
 17,191 
  
$
 (17,192)
(c)
  
$
 54,367 

(a)
All Other includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
(b)
Includes eliminations due to an intercompany capital lease.
(c)
Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies.

8.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

Our strategy surrounding the use of derivative instruments primarily focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  Our risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact.  To accomplish our objectives, we primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options.  Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.”  Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

We enter into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business.  We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio.  For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities.  We also engage in risk management of interest rate risk associated with debt financing and
 
 
60
 
foreign currency risk associated with future purchase obligations denominated in foreign currencies.  For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.”  The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.

The following table represents the gross notional volume of our outstanding derivative contracts as of June 30, 2013 and December 31, 2012:

Notional Volume of Derivative Instruments
                   
     
Volume
    
     
June 30,
  
December 31,
  
Unit of
   
2013 
  
2012 
  
Measure
Primary Risk Exposure
  
(in millions)
  
Commodity:
                
 
Power
    
 553 
    
 498 
  
MWhs
 
Coal
    
 5 
    
 10 
  
Tons
 
Natural Gas
    
 159 
    
 147 
  
MMBtus
 
Heating Oil and Gasoline
    
 5 
    
 6 
  
Gallons
 
Interest Rate
  
$
 197 
  
$
 235 
  
USD
                   
Interest Rate and Foreign Currency
  
$
 874 
  
$
 1,199 
  
USD

Fair Value Hedging Strategies

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

Cash Flow Hedging Strategies

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

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

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

At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers.  In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar.  We do not hedge all foreign currency exposure.
 
61
 
 
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS
 
The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheets at fair value.  The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes.  If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions.  In order to determine the relevant fair values of our derivative instruments, we also apply valuation adjustments for discounting, liquidity and credit quality.

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

According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the June 30, 2013 and December 31, 2012 condensed balance sheets, we netted $8 million and $7 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $28 million and $50 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.
 
62
 

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

Fair Value of Derivative Instruments
June 30, 2013
   
                         
Gross Amounts
  
Gross
  
Net Amounts of
     
Risk Management
          
of Risk
  
Amounts
  
Assets/Liabilities
     
Contracts
  
Hedging Contracts
  
Management
  
Offset in the
  
Presented in the
             
Interest Rate
  
Assets/
  
Statement of
  
Statement of
             
and Foreign
    
Liabilities
  
Financial
  
Financial
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Recognized
  
Position (b)
  
Position (c)
     
(in millions)
Current Risk Management Assets
  
$
 518 
  
$
 27 
  
$
 4 
  
$
 549 
  
$
 (362)
  
$
 187 
Long-term Risk Management Assets
    
 449 
    
 6 
    
 - 
    
 455 
    
 (138)
    
 317 
Total Assets
    
 967 
    
 33 
    
 4 
    
 1,004 
    
 (500)
    
 504 
                                       
Current Risk Management Liabilities
    
 458 
    
 29 
    
 1 
    
 488 
    
 (377)
    
 111 
Long-term Risk Management Liabilities
    
 312 
    
 2 
    
 17 
    
 331 
    
 (150)
    
 181 
Total Liabilities
    
 770 
    
 31 
    
 18 
    
 819 
    
 (527)
    
 292 
                                       
Total MTM Derivative Contract Net
                                    
 
Assets (Liabilities)
  
$
 197 
  
$
 2 
  
$
 (14)
  
$
 185 
  
$
 27 
  
$
 212 
                                       
Fair Value of Derivative Instruments
December 31, 2012
   
                       
Gross Amounts
  
Gross
  
Net Amounts of
     
Risk Management
          
of Risk
  
Amounts
  
Assets/Liabilities
     
Contracts
  
Hedging Contracts
  
Management
  
Offset in the
  
Presented in the
             
Interest Rate
  
Assets/
Statement of
  
Statement of
             
and Foreign
  
Liabilities
Financial
  
Financial
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Recognized
  
Position (b)
  
Position (c)
     
(in millions)
Current Risk Management Assets
  
$
 589 
  
$
 32 
  
$
 3 
  
$
 624 
  
$
 (433)
  
$
 191 
Long-term Risk Management Assets
    
 528 
    
 5 
    
 1 
    
 534 
    
 (166)
    
 368 
Total Assets
    
 1,117 
    
 37 
    
 4 
    
 1,158 
    
 (599)
    
 559 
                                       
Current Risk Management Liabilities
    
 546 
    
 43 
    
 35 
    
 624 
    
 (469)
    
 155 
Long-term Risk Management Liabilities
    
 383 
    
 6 
    
 6 
    
 395 
    
 (181)
    
 214 
Total Liabilities
    
 929 
    
 49 
    
 41 
    
 1,019 
    
 (650)
    
 369 
                                       
Total MTM Derivative Contract Net
                                    
 
Assets (Liabilities)
  
$
 188 
  
$
 (12)
  
$
 (37)
  
$
 139 
  
$
 51 
  
$
 190 

(a)
Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."
(b)
Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."  Amounts also include de-designated risk management contracts.
(c)
There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.

 
63
 
The table below presents our activity of derivative risk management contracts for the three and six months ended June 30, 2013 and 2012:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three and Six Months Ended June 30, 2013 and 2012
                         
   
Three Months Ended June 30,
  
Six Months Ended June 30,
Location of Gain (Loss)
  
2013 
  
2012 
  
2013 
  
2012 
   
(in millions)
Utility Operations Revenues
  
$
 5 
  
$
 4 
  
$
 13 
  
$
 14 
Other Revenues
    
 16 
    
 5 
    
 30 
    
 8 
Regulatory Assets (a)
    
 (8)
    
 (17)
    
 (5)
    
 (38)
Regulatory Liabilities (a)
    
 4 
    
 13 
    
 (3)
    
 27 
Total Gain (Loss) on Risk
                        
   Management Contracts
  
$
 17 
  
$
 5 
  
$
 35 
  
$
 11 
                         

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

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

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

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

Accounting for Fair Value Hedging Strategies

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

We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our condensed statements of income.  During the three and six months ended June 30, 2013, we recognized losses of $11 million and $12 million, respectively, on our hedging instruments and offsetting gains of $11 million and $12 million, respectively, on our long-term debt.  During the three and six months ended June 30, 2012, we recognized gains of $1 million and $2 million, respectively, on our hedging instruments and offsetting losses of $1 million and $2 million, respectively, on our long-term debt.  During the three and six months ended June 30, 2013 and 2012, hedge ineffectiveness was immaterial.
 
64
 

Accounting for Cash Flow Hedging Strategies

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

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

We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our condensed statements of income.  During the three and six months ended June 30, 2013 and 2012, we designated heating oil and gasoline derivatives as cash flow hedges.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Interest Expense on our condensed statements of income in those periods in which hedged interest payments occur.  During the three and six months ended June 30, 2013 and 2012, we designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Depreciation and Amortization expense on our condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.  During the three and six months ended June 30, 2013, we did not designate any foreign currency derivatives as cash flow hedges.  During the three and six months ended June 30, 2012, we designated foreign currency derivatives as cash flow hedges.

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

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2013 and 2012, see Note 2.
 
65
 

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

Impact of Cash Flow Hedges on the Condensed Balance Sheet
June 30, 2013
                       
             
Interest Rate
      
             
and Foreign
      
       
Commodity
  
Currency
  
Total
       
(in millions)
Hedging Assets (a)
  
$
 14 
  
$
 - 
  
$
 14 
Hedging Liabilities (a)
    
 12 
    
 2 
    
 14 
AOCI Gain (Loss) Net of Tax
    
 1 
    
 (25)
    
 (24)
Portion Expected to be Reclassified to Net
                  
 
Income During the Next Twelve Months
    
 (2)
    
 (4)
    
 (6)
                       
Impact of Cash Flow Hedges on the Condensed Balance Sheet
December 31, 2012
                       
             
Interest Rate
      
             
and Foreign
      
       
Commodity
  
Currency
  
Total
       
(in millions)
Hedging Assets (a)
  
$
 24 
  
$
 - 
  
$
 24 
Hedging Liabilities (a)
    
 36 
    
 37 
    
 73 
AOCI Gain (Loss) Net of Tax
    
 (8)
    
 (30)
    
 (38)
Portion Expected to be Reclassified to Net
                  
 
Income During the Next Twelve Months
    
 (8)
    
 (4)
    
 (12)

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

The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.  As of June 30, 2013, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions is 27 months.

Credit Risk

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

When we use standardized master agreements, these agreements may include collateral requirements.  These master agreements facilitate the netting of cash flows associated with a single counterparty.  Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk.  The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold.  The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy.  In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
 
66
 

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, we are obligated to post an additional amount of collateral if our credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and our total exposure.  On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts.  AEP and its subsidiaries have not experienced a downgrade below investment grade.  The following table represents: (a) our fair value of such derivative contracts, (b) the amount of collateral we would have been required to post for all derivative and non-derivative contracts if our credit ratings had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of June 30, 2013 and December 31, 2012:

     
June 30,
  
December 31,
     
2013 
  
2012 
     
(in millions)
Liabilities for Derivative Contracts with Credit Downgrade Triggers
  
$
 4 
  
$
 7 
Amount of Collateral AEP Subsidiaries Would Have Been
            
 
Required to Post
    
 48 
    
 32 
Amount Attributable to RTO and ISO Activities
    
 47 
    
 31 

In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million.  On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts.  The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of June 30, 2013 and December 31, 2012:

   
June 30,
  
December 31,
   
2013 
  
2012 
   
(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual
            
   Netting Arrangements
  
$
 360 
  
$
 469 
Amount of Cash Collateral Posted
    
 3 
    
 8 
Additional Settlement Liability if Cross Default Provision is Triggered
    
 252 
    
 328 

9.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.  Our market risk oversight staff independently monitors our valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures.  The CORC consists of our Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer.
 
67
 

For our commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated.  We typically obtain multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, we average the quoted bid and ask prices.  In certain circumstances, we may discard a broker quote if it is a clear outlier.  We use a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated, we include these locations within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs.  Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.  The main driver of our contracts being classified as Level 3 is the inability to substantiate our energy price curves in the market.  A significant portion of our Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

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

Assets in the nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds.  Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

Fair Value Measurements of Long-term Debt

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange.

The book values and fair values of Long-term Debt as of June 30, 2013 and December 31, 2012 are summarized in the following table:

   
June 30, 2013
  
December 31, 2012
   
Book Value
  
Fair Value
  
Book Value
  
Fair Value
   
(in millions)
Long-term Debt
  
$
 17,618 
  
$
 19,509 
  
$
 17,757 
  
$
 20,907 

 
68
 
Fair Value Measurements of Other Temporary Investments

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

The following is a summary of Other Temporary Investments:

       
June 30, 2013
           
Gross
  
Gross
  
Estimated
           
 Unrealized
  
Unrealized
  
 Fair
Other Temporary Investments
  
Cost
  
Gains
  
Losses
  
Value
       
(in millions)
Restricted Cash (a)
  
$
 204 
  
$
 - 
  
$
 - 
  
$
 204 
Fixed Income Securities:
                        
 
Mutual Funds
    
 76 
    
 - 
    
 - 
    
 76 
Equity Securities - Mutual Funds
    
 10 
    
 8 
    
 - 
    
 18 
Total Other Temporary Investments
  
$
 290 
  
$
 8 
  
$
 - 
  
$
 298 
                             
       
December 31, 2012
           
Gross
  
Gross
  
Estimated
           
 Unrealized
  
Unrealized
  
 Fair
Other Temporary Investments
  
Cost
  
Gains
  
Losses
  
Value
       
(in millions)
Restricted Cash (a)
  
$
 241 
  
$
 - 
  
$
 - 
  
$
 241 
Fixed Income Securities:
                        
 
Mutual Funds
    
 65 
    
 2 
    
 - 
    
 67 
Equity Securities - Mutual Funds
    
 10 
    
 6 
    
 - 
    
 16 
Total Other Temporary Investments
  
$
 316 
  
$
 8 
  
$
 - 
  
$
 324 
                             
(a)
Primarily represents amounts held for the repayment of debt.

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

 
Three Months Ended June 30,
  
Six Months Ended June 30,
 
2013 
  
2012 
  
2013 
  
2012 
 
(in millions)
Proceeds from Investment Sales
$
 - 
  
$
 - 
  
$
 - 
  
$
 - 
Purchases of Investments
  
 - 
    
 1 
    
 11 
    
 1 
Gross Realized Gains on Investment Sales
  
 - 
    
 - 
    
 - 
    
 - 
Gross Realized Losses on Investment Sales
  
 - 
    
 - 
    
 - 
    
 - 

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

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

 
69
 
Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

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

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

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

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

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

     
June 30, 2013
  
December 31, 2012
     
Estimated
  
Gross
  
Other-Than-
  
Estimated
  
Gross
  
Other-Than-
   
Fair
Unrealized
Temporary
Fair
Unrealized
Temporary
   
Value
Gains
Impairments
Value
Gains
Impairments
     
(in millions)
Cash and Cash Equivalents
  
$
 14 
  
$
 - 
  
$
 - 
  
$
 17 
  
$
 - 
  
$
 - 
Fixed Income Securities:
                                    
 
United States Government
    
 605 
    
 37 
    
 (2)
    
 648 
    
 58 
    
 (1)
 
Corporate Debt
    
 35 
    
 3 
    
 (2)
    
 35 
    
 5 
    
 (1)
 
State and Local Government
    
 262 
    
 - 
    
 (3)
    
 270 
    
 1 
    
 (1)
 
  Subtotal Fixed Income Securities
  
 902 
    
 40 
    
 (7)
    
 953 
    
 64 
    
 (3)
Equity Securities - Domestic
    
 875 
    
 373 
    
 (82)
    
 736 
    
 285 
    
 (77)
Spent Nuclear Fuel and
                                    
 
Decommissioning Trusts
  
$
 1,791 
  
$
 413 
  
$
 (89)
  
$
 1,706 
  
$
 349 
  
$
 (80)

 
70
 
The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2013 and 2012:

 
Three Months Ended June 30,
  
Six Months Ended June 30,
 
2013 
  
2012 
  
2013 
  
2012 
 
(in millions)
Proceeds from Investment Sales
$
 217 
  
$
 183 
  
$
 385 
  
$
 517 
Purchases of Investments
  
 227 
    
 192 
    
 412 
    
 545 
Gross Realized Gains on Investment Sales
  
 9 
    
 3 
    
 12 
    
 5 
Gross Realized Losses on Investment Sales
  
 8 
    
 1 
    
 10 
    
 2 

The adjusted cost of fixed income securities was $862 million and $889 million as of June 30, 2013 and December 31, 2012, respectively.  The adjusted cost of equity securities was $502 million and $451 million as of June 30, 2013 and December 31, 2012, respectively.

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

 
Fair Value of
 
Fixed Income
 
Securities
 
(in millions)
Within 1 year
$
 79 
1 year – 5 years
  
 340 
5 years – 10 years
  
 238 
After 10 years
  
 245 
Total
$
 902 

 
71
 
Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2013 and December 31, 2012.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in our valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2013
                       
     
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in millions)
                                 
Cash and Cash Equivalents (a)
$
 10 
  
$
 1 
  
$
 - 
  
$
 106 
  
$
 117 
                                 
Other Temporary Investments
                            
Restricted Cash (a)
  
 186 
    
 6 
    
 - 
    
 12 
    
 204 
Fixed Income Securities:
                            
 
Mutual Funds
  
 76 
    
 - 
    
 - 
    
 - 
    
 76 
Equity Securities - Mutual Funds (b)
  
 18 
    
 - 
    
 - 
    
 - 
    
 18 
Total Other Temporary Investments
  
 280 
    
 6 
    
 - 
    
 12 
    
 298 
                                 
Risk Management Assets
                            
Risk Management Commodity Contracts (c) (d)
  
 38 
    
 776 
    
 142 
    
 (479)
    
 477 
Cash Flow Hedges:
                            
 
Commodity Hedges (c)
  
 4 
    
 28 
    
 - 
    
 (18)
    
 14 
Fair Value Hedges
  
 - 
    
 1 
    
 - 
    
 3 
    
 4 
De-designated Risk Management Contracts (e)
  
 - 
    
 - 
    
 - 
    
 9 
    
 9 
Total Risk Management Assets
  
 42 
    
 805 
    
 142 
    
 (485)
    
 504 
                                 
Spent Nuclear Fuel and Decommissioning Trusts
                            
Cash and Cash Equivalents (f)
  
 3 
    
 - 
    
 - 
    
 11 
    
 14 
Fixed Income Securities:
                            
 
United States Government
  
 - 
    
 605 
    
 - 
    
 - 
    
 605 
 
Corporate Debt
  
 - 
    
 35 
    
 - 
    
 - 
    
 35 
 
State and Local Government
  
 - 
    
 262 
    
 - 
    
 - 
    
 262 
   
Subtotal Fixed Income Securities
  
 - 
    
 902 
    
 - 
    
 - 
    
 902 
Equity Securities - Domestic (b)
  
 875 
    
 - 
    
 - 
    
 - 
    
 875 
Total Spent Nuclear Fuel and Decommissioning Trusts
  
 878 
    
 902 
    
 - 
    
 11 
    
 1,791 
                                 
Total Assets
$
 1,210 
  
$
 1,714 
  
$
 142 
  
$
 (356)
  
$
 2,710 
                                 
Liabilities:
                            
                                 
Risk Management Liabilities
                            
Risk Management Commodity Contracts (c) (d)
$
 42 
  
$
 697 
  
$
 20 
  
$
 (497)
  
$
 262 
Cash Flow Hedges:
                            
 
Commodity Hedges (c)
  
 - 
    
 30 
    
 - 
    
 (18)
    
 12 
 
Interest Rate/Foreign Currency Hedges
  
 - 
    
 2 
    
 - 
    
 - 
    
 2 
Fair Value Hedges
  
 - 
    
 13 
    
 - 
    
 3 
    
 16 
Total Risk Management Liabilities
$
 42 
  
$
 742 
  
$
 20 
  
$
 (512)
  
$
 292 

 
72
 


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

(a)
Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties.  Level 1 and Level 2 amounts primarily represent investments in money market funds.
(b)
Amounts represent publicly traded equity securities and equity-based mutual funds.
(c)
Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.''
(d)
The June 30, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $3 million in 2013, ($3) million in periods 2014-2016 and ($4) million in periods 2017-2018;  Level 2 matures $12 million in 2013, $53 million in periods 2014-2016, $8 million in periods 2017-2018 and $6 million in periods 2019-2030;  Level 3 matures $19 million in 2013, $50 million in periods 2014-2016, $30 million in periods 2017-2018 and $23 million in periods 2019-2030.  Risk management commodity contracts are substantially comprised of power contracts.
(e)
Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for ''Derivatives and Hedging.''  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This MTM value will be amortized into revenues over the remaining life of the contracts.
(f)
Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(g)
The December 31, 2012 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $9 million in 2013, ($3) million in periods 2014-2016 and ($4) million in periods 2017-2018;  Level 2 matures $16 million in 2013, $61 million in periods 2014-2016, $16 million in periods 2017-2018 and $7 million in periods 2019-2030;  Level 3 matures $18 million in 2013, $31 million in periods 2014-2016, $13 million in periods 2017-2018 and $24 million in periods 2019-2030.  Risk management commodity contracts are substantially comprised of power contracts.

There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2013 and 2012.

 
73
 
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as Level 3 in the fair value hierarchy:

     
Net Risk Management
Three Months Ended June 30, 2013
  
Assets (Liabilities)
     
(in millions)
Balance as of March 31, 2013
  
$
 76 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
    
 (1)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
      
 
Relating to Assets Still Held at the Reporting Date (a)
    
 26 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
    
 (1)
Purchases, Issuances and Settlements (c)
    
 (2)
Transfers into Level 3 (d) (e)
    
 12 
Transfers out of Level 3 (e) (f)
    
 1 
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
    
 11 
Balance as of June 30, 2013
  
$
 122 

     
Net Risk Management
Three Months Ended June 30, 2012
  
Assets (Liabilities)
     
(in millions)
Balance as of March 31, 2012
  
$
 92 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
    
 (11)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
      
 
Relating to Assets Still Held at the Reporting Date (a)
    
 4 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
    
 - 
Purchases, Issuances and Settlements (c)
    
 15 
Transfers into Level 3 (d) (e)
    
 (1)
Transfers out of Level 3 (e) (f)
    
 (8)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
    
 6 
Balance as of June 30, 2012
  
$
 97 

 
74
 
     
Net Risk Management
Six Months Ended June 30, 2013
  
Assets (Liabilities)
     
(in millions)
Balance as of December 31, 2012
  
$
 86 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
    
 (12)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
      
 
Relating to Assets Still Held at the Reporting Date (a)
    
 22 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
    
 - 
Purchases, Issuances and Settlements (c)
    
 (1)
Transfers into Level 3 (d) (e)
    
 18 
Transfers out of Level 3 (e) (f)
    
 1 
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
    
 8 
Balance as of June 30, 2013
  
$
 122 

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

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

The following table quantifies the significant unobservable inputs used in developing the fair value of our Level 3 positions as of June 30, 2013:

   
Fair Value
  
Valuation
  
Significant
  
Input/Range
 
Assets
  
Liabilities
Technique
Unobservable Input
  
Low
  
High
   
(in millions)
                    
Energy Contracts
  
$
 128 
  
$
 16 
  
Discounted Cash Flow
  
Forward Market Price (a)
  
$
 10.17 
  
$
 140.98 
                   
Counterparty Credit Risk (b)
    
356 
FTRs
    
 14 
    
 4 
  
Discounted Cash Flow
  
Forward Market Price (a)
    
 (26.98)
    
 11.19 
Total
  
$
 142 
  
$
 20 
                    

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

 
75
 
10.  INCOME TAXES

AEP System Tax Allocation Agreement

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

Federal and State Income Tax Audit Status

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

We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions.  These taxing authorities routinely examine our tax returns and we are currently under examination in several state and local jurisdictions.  However, we believe that we have filed tax returns with positions that may be challenged by these tax authorities.  We believe that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and the ultimate resolution of these audits will not materially impact net income.  We are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2008.

Uncertain Tax Positions

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

The tax benefit associated with the U.K. Windfall Tax was reported as a $64 million unrecognized tax benefit as of December 31, 2012 and was included in the amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate.  Therefore, the related amounts reported as of December 31, 2012 have been reduced due to the recognition of the U.K. Windfall Tax benefit during the second quarter of 2013.
 
76
 

11.  FINANCING ACTIVITIES

Long-term Debt

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

Type of Debt
  
June 30, 2013
  
December 31, 2012
   
(in millions)
Senior Unsecured Notes
  
$
 12,458 
  
$
 12,712 
Pollution Control Bonds
    
 1,982 
    
 1,958 
Notes Payable
    
 462 
    
 427 
Securitization Bonds
    
 2,150 
    
 2,281 
Spent Nuclear Fuel Obligation (a)
    
 265 
    
 265 
Other Long-term Debt
    
 338 
    
 140 
Fair Value of Interest Rate Hedges
    
 (10)
    
 3 
Unamortized Discount, Net
    
 (27)
    
 (29)
Total Long-term Debt Outstanding
    
 17,618 
    
 17,757 
Long-term Debt Due Within One Year
    
 1,819 
    
 2,171 
Long-term Debt
  
$
 15,799 
  
$
 15,586 

 
(a)
Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal.  The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983.  Trust fund assets related to this obligation were $308 million and $308 million as of June 30, 2013 and December 31, 2012, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets.

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

         
Principal
    
Interest
    
Company
  
Type of Debt
  
Amount
    
Rate
  
Due Date
Issuances:
    
(in millions)
  
(%)
    
AEP
    
Other Long-term Debt
  
$
 200 
(a)
  
Variable
  
2015 
I&M
    
Senior Unsecured Notes
    
 250 
    
3.20 
  
2023 
I&M
  
Notes Payable
    
 101 
    
Variable
  
2017 
OPCo
  
Pollution Control Bonds
  
 50 
    
Variable
  
2014 
                       
Non-Registrant:
                    
AEPTCo
  
Senior Unsecured Notes
    
 25 
    
4.83 
  
2043 
TCC
  
Pollution Control Bonds
  
 120 
    
4.00 
  
2030 
TNC
    
Senior Unsecured Notes
    
 125 
    
3.09 
  
2023 
TNC
    
Senior Unsecured Notes
    
 75 
    
4.48 
  
2043 
Total Issuances
      
$
 946 
(b)
        

 
(a)
Draw on a $1 billion term credit facility due in May 2015.
 
(b)
Amount indicated on the statement of cash flows is net of issuance costs and premium or discount and will not tie to the total issuances.

 
77
 
         
Principal
    
Interest
    
Company
  
Type of Debt
  
Amount Paid
    
Rate
  
Due Date
Retirements and
    
 (in millions)
  
(%)
    
 
Principal Payments:
                    
I&M
  
Notes Payable
  
$
 6 
    
5.44 
  
2013 
I&M
  
Notes Payable
    
 10 
    
4.00 
  
2014 
I&M
  
Notes Payable
    
 8 
    
Variable
  
2015 
I&M
  
Notes Payable
    
 10 
    
Variable
  
2016 
I&M
  
Notes Payable
    
 7 
    
2.12 
  
2016 
I&M
  
Notes Payable
    
 21 
    
Variable
  
2016 
I&M
  
Pollution Control Bonds
    
 40 
    
5.25 
  
2025 
I&M
  
Other Long-term Debt
    
 2 
    
Variable
  
2015 
OPCo
  
Senior Unsecured Notes
    
 250 
    
5.50 
  
2013 
OPCo
  
Senior Unsecured Notes
    
 250 
    
5.50 
  
2013 
OPCo
  
Pollution Control Bonds
    
 56 
    
5.10 
  
2013 
OPCo
  
Pollution Control Bonds
    
 50 
    
5.15 
  
2026 
SWEPCo
  
Notes Payable
    
 1 
    
4.58 
  
2032 
                       
Non-Registrant:
                    
AEP Subsidiaries
  
Notes Payable
    
 1 
    
Variable
  
2017 
AEP Subsidiaries
  
Notes Payable
    
 1 
    
7.59 - 8.03
  
2026 
AEGCo
  
Senior Unsecured Notes
    
 4 
    
6.33 
  
2037 
TCC
  
Securitization Bonds
    
 67 
    
4.98 
  
2013 
TCC
  
Securitization Bonds
    
 38 
    
5.96 
  
2013 
TCC
  
Securitization Bonds
    
 26 
    
0.88 
  
2017 
TNC
  
Senior Unsecured Notes
    
 225 
    
5.50 
  
2013 
Total Retirements and
                    
 
Principal Payments
      
$
 1,073 
          

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

In July 2013, I&M retired $12 million of Notes Payable related to DCC Fuel.
 
In July 2013, OPCo retired $65 million of 4.9% Pollution Control Bonds due in 2037 and issued $65 million of variable rate Pollution Control Bonds due in 2014.
 
As of June 30, 2013, trustees held, on our behalf, $504 million of our reacquired Pollution Control Bonds.

Dividend Restrictions

Parent Restrictions

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

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

 
78
 
Utility Subsidiaries’ Restrictions

Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.  Specifically, several of our public utility subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%.

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

Our outstanding short-term debt was as follows:
                           
     
June 30, 2013
  
December 31, 2012
     
Outstanding
  
Interest
  
Outstanding
  
Interest
Type of Debt
Amount
Rate (a)
  
Amount
Rate (a)
   
(in millions)
        
(in millions)
      
Securitized Debt for Receivables (b)
  
$
 688 
  
 0.23 
%
  
$
 657 
  
 0.26 
%
Commercial Paper
    
 850 
  
 0.32 
%
    
 321 
  
 0.42 
%
Line of Credit – Sabine (c)
    
 - 
  
 - 
%
    
 3 
  
 1.82 
%
Total Short-term Debt
  
$
 1,538 
        
$
 981 
      

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

Credit Facilities

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

Securitized Accounts Receivable – AEP Credit

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

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

Accounts receivable information for AEP Credit is as follows:

     
Three Months Ended
  
Six Months Ended
  
     
June 30,
  
June 30,
  
     
2013 
  
2012 
  
2013 
  
2012 
  
   
(dollars in millions)
  
Effective Interest Rates on Securitization of
                          
 
Accounts Receivable
    
 0.22 
%
  
 0.26 
%
  
 0.23 
%
  
 0.26 
%
Net Uncollectible Accounts Receivable
                          
 
Written Off
  
$
 7 
  
$
 6 
  
$
 14 
  
$
 14 
  

 
79
 
     
June 30,
  
December 31,
     
2013 
  
2012 
     
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
            
 
Less Uncollectible Accounts
  
$
 954 
  
$
 835 
Total Principal Outstanding
    
 688 
    
 657 
Delinquent Securitized Accounts Receivable
    
 45 
    
 37 
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable
    
 21 
    
 21 
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable
    
 369 
    
 316 

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

12.  VARIABLE INTEREST ENTITIES

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE.  A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.  Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.”  In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE’s variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors.  We believe that significant assumptions and judgments were applied consistently.

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

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the three months ended June 30, 2013 and 2012 were $40 million and $36 million, respectively, and for the six months ended June 30, 2013 and 2012 were $84 million and $91 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on the condensed balance sheets.

I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI LLC (collectively DCC Fuel).  DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the leases for the three months ended June 30, 2013 and 2012 were $38 million and $42 million, respectively, and for the six months ended June 30, 2013 and 2012 were $64 million and $59 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months.  Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  See the tables below for the classification of DCC Fuel’s assets and liabilities on the condensed balance sheets.
 
80
 

AEP Credit is a wholly-owned subsidiary of AEP.  AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements.  AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings.  Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing.  Based on our control of AEP Credit, management has concluded that we are the primary beneficiary and are required to consolidate its assets and liabilities.  See the tables below for the classification of AEP Credit’s assets and liabilities on the condensed balance sheets.  See “Securitized Accounts Receivable – AEP Credit” section of Note 11.

Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.  Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant.  Therefore, TCC is required to consolidate Transition Funding.  The securitized bonds totaled $2.2 billion and $2.3 billion as of June 30, 2013 and December 31, 2012, respectively, and are included in current and long-term debt on the condensed balance sheets.  Transition Funding has securitized transition assets of $2 billion and $2.1 billion as of June 30, 2013 and December 31, 2012, respectively, which are presented separately on the face of the condensed balance sheets.  The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT.  The securitization bonds are payable only from and secured by the securitized transition assets.  The bondholders have no recourse to TCC or any other AEP entity.  TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs.  See the tables below for the classification of Transition Funding’s assets and liabilities on the condensed balance sheets.

Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance.  EIS has multiple protected cells.  Neither AEP nor its subsidiaries have an equity investment in EIS.  The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance.  Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims.  Based on our control and the structure of the protected cell and EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate its assets and liabilities.  Our insurance premium expense to the protected cell for the three months ended June 30, 2013 and 2012 were $14 thousand and $0, respectively, and for the six months ended June 30, 2013 and 2012 were $15 million and $15 million, respectively.  See the tables below for the classification of the protected cell’s assets and liabilities on the condensed balance sheets.  The amount reported as equity is the protected cell’s policy holders’ surplus.
 
81
 

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

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
June 30, 2013
(in millions)
                                 
                       
TCC
      
     
SWEPCo
  
I&M
        
Transition
  
Protected Cell
     
Sabine
DCC Fuel
AEP Credit
Funding
  
of EIS
ASSETS
                              
Current Assets
  
$
 66 
  
$
 161 
  
$
 963 
  
$
 221 
  
$
 136 
Net Property, Plant and Equipment
    
 163 
    
 219 
    
 - 
    
 - 
    
 - 
Other Noncurrent Assets
    
 66 
    
 104 
    
 - 
    
 2,060 
(a)
  
 5 
Total Assets
  
$
 295 
  
$
 484 
  
$
 963 
  
$
 2,281 
  
$
 141 
                                 
LIABILITIES AND EQUITY
                              
Current Liabilities
  
$
 31 
  
$
 143 
  
$
 904 
  
$
 307 
  
$
 42 
Noncurrent Liabilities
    
 264 
    
 341 
    
 1 
    
 1,956 
    
 68 
Equity
    
 - 
    
 - 
    
 58 
    
 18 
    
 31 
Total Liabilities and Equity
  
$
 295 
  
$
 484 
  
$
 963 
  
$
 2,281 
  
$
 141 
                               
(a)      Includes an intercompany item eliminated in consolidation of $86 million.          
 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2012
(in millions)
                               
                     
TCC
      
   
SWEPCo
  
I&M
        
Transition
  
Protected Cell
   
Sabine
DCC Fuel
AEP Credit
Funding
  
of EIS
ASSETS
                              
Current Assets
  
$
 57 
  
$
 133 
  
$
 843 
  
$
 250 
  
$
 130 
Net Property, Plant and Equipment
    
 170 
    
 176 
    
 - 
    
 - 
    
 - 
Other Noncurrent Assets
    
 55 
    
 92 
    
 1 
    
 2,167 
(a)
  
 4 
Total Assets
  
$
 282 
  
$
 401 
  
$
 844 
  
$
 2,417 
  
$
 134 
                               
LIABILITIES AND EQUITY
                              
Current Liabilities
  
$
 32 
  
$
 121 
  
$
 800 
  
$
 304 
  
$
 43 
Noncurrent Liabilities
    
 250 
    
 280 
    
 1 
    
 2,095 
    
 66 
Equity
    
 - 
    
 - 
    
 43 
    
 18 
    
 25 
Total Liabilities and Equity
  
$
 282 
  
$
 401 
  
$
 844 
  
$
 2,417 
  
$
 134 
                               
(a)      Includes an intercompany item eliminated in consolidation of $89 million.
 
 
82
 
DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and voting rights equally.  Each entity guarantees 50% of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  SWEPCo’s total billings from DHLC for the three months ended June 30, 2013 and 2012 were $13 million and $20 million, respectively, and for the six months ended June 30, 2013 and 2012 were $31 million and $34 million, respectively.  We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC.  Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets.

Our investment in DHLC was:

   
June 30, 2013
  
December 31, 2012
   
As Reported on
  
Maximum
  
As Reported on
  
Maximum
   
the Balance Sheet
Exposure
  
the Balance Sheet
  
Exposure
   
(in millions)
Capital Contribution from SWEPCo
  
$
 8 
  
$
 8 
  
$
 8 
  
$
 8 
Retained Earnings
    
 1 
    
 1 
    
 1 
    
 1 
SWEPCo's Guarantee of Debt
    
 - 
    
 50 
    
 - 
    
 49 
                         
Total Investment in DHLC
  
$
 9 
  
$
 59 
  
$
 9 
  
$
 58 

We and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH).  PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region.  PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy.  Provisions exist within the PATH-WV agreement that make it a VIE.  The “Allegheny Series” is not considered a VIE.  We are not required to consolidate PATH-WV as we are not the primary beneficiary, although we hold a significant variable interest in PATH-WV.  Our equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on our condensed balance sheets.  We and FirstEnergy share the returns and losses equally in PATH-WV.  Our subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements.  The entities recover costs through regulated rates.

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

Our investment in PATH-WV was:

   
June 30, 2013
  
December 31, 2012
   
As Reported on
  
Maximum
  
As Reported on
  
Maximum
   
the Balance Sheet
Exposure
the Balance Sheet
Exposure
       
(in millions)
      
 
Capital Contribution from AEP
$
 19 
  
$
 19 
  
$
 19 
  
$
 19 
 
Retained Earnings
  
 13 
    
 13 
    
 12 
    
 12 
                         
 
Total Investment in PATH-WV
$
 32 
  
$
 32 
  
$
 31 
  
$
 31 

 
83
 
13.  SUSTAINABLE COST REDUCTIONS

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

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

   
Sustainable Cost
   
Reduction Activity
   
(in millions)
Balance as of December 31, 2012
  
$
 25 
Incurred
    
 16 
Settled
    
 (29)
Adjustments
    
 (6)
Balance as of June 30, 2013
  
$
 6 

These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income.  Approximately 94% of the expense was within the Utility Operations segment.  The remaining liability is included in Other Current Liabilities on the condensed balance sheets.  We do not expect additional costs to be incurred related to this initiative.


 
84
 

 
APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

 
85
 

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

EXECUTIVE OVERVIEW

Regulatory Activity

Plant Transfers and Termination of Interconnection Agreement

Based upon the PUCO’s approval of OPCo’s corporate separation plan in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations, transfer these assets to AEPGenCo and subsequently transfer, at net book value (NBV), OPCo’s current two-thirds ownership in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests.  In December 2012, APCo filed requests with the Virginia SCC and WVPSC for the approval of the plant transfers discussed above.  APCo is currently pursuing cost recovery of these plants in West Virginia and plans to pursue cost recovery in Virginia.  In April 2013, the FERC issued orders approving the merger of APCo and WPCo and approving the transfer of the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo, to be effective using the requested date of December 31, 2013.  In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo.  This issue remains pending before the FERC.  In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.  Hearings in the plant transfer cases were held at the Virginia SCC in June 2013 and at the WVPSC in July 2013.  See the “Plant Transfers” section of APCo Rate Matters in Note 3.
 
 
Additionally, the AEP East Companies requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  Under the PCA, APCo would be individually responsible for planning its capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies.  In March 2013, a revised PCA was filed at the FERC that included certain clarifying wording changes agreed upon by intervenors.  A decision is pending at the FERC.  See the “Corporate Separation and Termination of Interconnection Agreement” section of Note 3.

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

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

2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs effective February 2014 over a one-year period.  APCo has deferred $28 million as of June 30, 2013 for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $11 million of unrecognized equity carrying costs.  Hearings at the Virginia SCC are scheduled for August 2013.  If the Virginia SCC were to disallow any portion of the environmental RAC, it could reduce future net income and cash flows.  See “2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing” section of Note 3.

2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing

In March 2013, APCo filed with the Virginia SCC for an increase in its generation RAC revenues of $12 million for a total of $38 million annually to collect costs related to the Dresden Plant.  The generation RAC increase is expected to be effective in March 2014.  APCo has deferred $4 million as of June 30, 2013 for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $4 million of unrecognized equity carrying costs.  Hearings at the Virginia SCC are scheduled for August 2013.  If the Virginia SCC were to disallow any portion of the generation RAC, it could reduce future net income and cash flows.  See “2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing” section of Note 3.
 
86
 

Securitization of Regulatory Assets

In March 2012, West Virginia passed securitization legislation which allows the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred Expanded Net Energy Charge (ENEC) balances and other ENEC related assets.  In August 2012, APCo and WPCo filed with the WVPSC a request for a financing order to securitize $422 million related to APCo’s December 2011 under-recovered ENEC deferral balance, other ENEC-related assets and related financing costs.  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.  Hearings at the WVPSC are scheduled for July 2013.

WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting approval to merge WPCo into APCo.  In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC.  In April 2013, the FERC approved the WPCo merger into APCo.  Hearings were held at the Virginia SCC in June 2013.  In June 2013, the WVPSC issued an order consolidating this case with APCo’s plant asset transfer case.  Hearings were held at the WVPSC in July 2013.  See the “Plant Transfers” and “WPCo Merger with APCo” sections of APCo Rate Matters in Note 3.

Litigation and Environmental Issues

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 153.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 220 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
                      
                           
KWh Sales/Degree Days
                      
                           
Summary of KWh Energy Sales
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
 
2013 
  
2012 
  
2013 
  
2012 
     
(in millions of KWhs)
Retail:
                      
 
Residential
  
 2,256 
    
 2,184 
    
 6,257 
    
 5,634 
 
Commercial
  
 1,617 
    
 1,683 
    
 3,359 
    
 3,309 
 
Industrial
  
 2,655 
    
 2,702 
    
 5,243 
    
 5,306 
 
Miscellaneous
  
 198 
    
 201 
    
 415 
    
 402 
Total Retail (a)
  
 6,726 
    
 6,770 
    
 15,274 
    
 14,651 
                       
Wholesale
  
 1,788 
    
 1,492 
    
 4,069 
    
 2,873 
                       
Total KWhs
  
 8,514 
    
 8,262 
    
 19,343 
    
 17,524 
                           
(a)
Represents energy delivered to distribution customers.
 
 
87
 
Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

 
Summary of Heating and Cooling Degree Days
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
     
(in degree days)
 
Actual - Heating (a)
  
 92 
    
 61 
    
 1,497 
    
 983 
 
Normal - Heating (b)
  
 93 
    
 97 
    
 1,405 
    
 1,440 
                           
 
Actual - Cooling (c)
  
 388 
    
 419 
    
 388 
    
 444 
 
Normal - Cooling (b)
  
 360 
    
 354 
    
 367 
    
 360 
                           
 
(a)
Eastern Region heating degree days are calculated on a 55 degree temperature base.
 
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
 
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.

 
88
 


Second Quarter of 2013 Compared to Second Quarter of 2012
                 
 
Reconciliation of Second Quarter of 2012 to Second Quarter of 2013
 
Net Income
 
(in millions)
                 
 
Second Quarter of 2012
        
$
 62 
                 
 
Changes in Gross Margin:
            
 
Retail Margins
          
 (26)
 
Off-system Sales
          
 (1)
 
Transmission Revenues
          
 2 
 
Other Revenues
          
 3 
 
Total Change in Gross Margin
          
 (22)
               
 
Changes in Expenses and Other:
            
 
Other Operation and Maintenance
          
 (28)
 
Depreciation and Amortization
          
 2 
 
Taxes Other Than Income Taxes
          
 (3)
 
Carrying Costs Income
          
 (2)
 
Other Income
          
 2 
 
Interest Expense
          
 4 
 
Total Change in Expenses and Other
          
 (25)
                 
 
Income Tax Expense
          
 15 
                 
 
Second Quarter of 2013
        
$
 30 

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

·
Retail Margins decreased $26 million primarily due to the following:
 
·
A $9 million deferral of additional wind purchase costs in the second quarter of 2012 as a result of the June 2012 Virginia SCC fuel factor order.
 
·
A $6 million net decrease in rates primarily due to the expiration of the Virginia Environmental Rate Adjustment Clause in March 2013.
 
·
A $4 million decrease in revenues due to a 0.5% decrease in weather-normalized retail sales.

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

·
Other Operation and Maintenance expenses increased $28 million primarily due to the following:
 
·
A $10 million increase in distribution maintenance expense primarily due to the June 2013 storms.
  
 
·
A $5 million increase in generation plant maintenance expenses due to Mountaineer Plant routine outages in 2013.
  
 
·
A $5 million increase in provisions for uncollectible accounts.
  
 
·
A $4 million increase in transmission expenses due to higher Network Integration Transmission Service (NITS) expenses.  These expenses are offset in Transmission Revenues.
  
 
·
A $3 million increase due to the change in the recovery position of transmission costs for the Virginia Transmission Rate Adjustment Clause as allowed by the Virginia SCC.
  
·
Taxes Other Than Income Taxes expenses increased $3 million primarily due to an increase in the Virginia State Minimum Tax accrual and an increase in real and personal property tax amortization.
·
Interest Expense decreased $4 million primarily due to lower long-term interest rates.
·
Income Tax Expense decreased $15 million primarily due to a decrease in pretax book income.

 
89
 


Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
                     
 
Reconciliation of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2013
 
Net Income
 
(in millions)
                     
   
Six Months Ended June 30, 2012
        
$
 138 
  
                     
   
Changes in Gross Margin:
              
   
Retail Margins
          
 35 
  
   
Off-system Sales
          
 (2)
  
   
Transmission Revenues
          
 4 
  
   
Other Revenues
          
 1 
  
   
Total Change in Gross Margin
          
 38 
  
                   
   
Changes in Expenses and Other:
              
   
Other Operation and Maintenance
          
 (86)
  
   
Depreciation and Amortization
          
 (6)
  
   
Taxes Other Than Income Taxes
          
 (3)
  
   
Carrying Costs Income
          
 (10)
  
   
Other Income
          
 3 
  
   
Interest Expense
          
 7 
  
   
Total Change in Expenses and Other
          
 (95)
  
                     
   
Income Tax Expense
          
 19 
  
                     
   
Six Months Ended June 30, 2013
        
$
 100 
  

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 $35 million primarily due to the following:
 
·
A $37 million increase in weather-related usage primarily due to a 52% increase in heating degree days.
 
·
A $21 million increase due to higher rates in Virginia and West Virginia.  For this increase, $7 million have a corresponding increase in Depreciation and Amortization expenses below.
 
These increases were partially offset by:
 
·
A $13 million increase in other variable electric generation expenses.
 
·
A $9 million deferral of additional wind purchase costs in the second quarter of 2012 as a result of the June 2012 Virginia SCC fuel factor order.

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

·
Other Operation and Maintenance expenses increased $86 million primarily due to the following:
 
·
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 $25 million increase in distribution maintenance expense primarily due to storms in January and June 2013.
  
 
·
An $11 million increase in generation plant maintenance expenses due to Mountaineer Plant routine outages in 2013.
  
·
Depreciation and Amortization expenses increased $6 million primarily due to the following:
 
·
A $3 million increase as a result of increased depreciation rates in Virginia effective February 2012.  The majority of this increase in depreciation is offset within Gross Margin.
  
 
·
A $3 million increase as a result of the Dresden Plant being placed in service in late January 2012.
  
·
Taxes Other Than Income Taxes expenses increased $3 million primarily due to an increase in the Virginia State Minimum Tax accrual and an increase in real and personal property tax amortization.
 
 
90
 
·
Carrying Costs Income decreased $10 million primarily due to an increased recovery of Virginia environmental costs in new base rates as approved by the Virginia SCC in late January 2012 and decreased carrying charges related to Dresden Plant.
·
Other Income increased $3 million primarily due to the following:
 
·
A $1 million increase in equity AFUDC.
  
 
·
A $1 million increase in interest income related to the 2009-2010 federal income tax audit.
  
·
Interest Expense decreased $7 million primarily due to lower long-term interest rates.
·
Income Tax Expense decreased $19 million primarily due to a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 220 for a discussion of accounting pronouncements.

 
91
 

 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
For the Three and Six Months Ended June 30, 2013 and 2012
 
(in thousands)
 
(Unaudited)
   
     
Three Months Ended
  
Six Months Ended
       
June 30,
  
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
 
REVENUES
                      
 
Electric Generation, Transmission and Distribution
  
$
 670,249 
  
$
 647,236 
  
$
 1,542,981 
  
$
 1,385,835 
 
Sales to AEP Affiliates
    
 73,893 
    
 67,043 
    
 150,753 
    
 131,344 
 
Other Revenues
    
 2,362 
    
 2,182 
    
 4,264 
    
 4,758 
 
TOTAL REVENUES
    
 746,504 
    
 716,461 
    
 1,697,998 
    
 1,521,937 
                           
 
EXPENSES
                        
 
Fuel and Other Consumables Used for Electric Generation
    
 163,521 
    
 181,653 
    
 368,460 
    
 368,537 
 
Purchased Electricity for Resale
    
 59,487 
    
 44,869 
    
 124,943 
    
 110,225 
 
Purchased Electricity from AEP Affiliates
    
 181,856 
    
 125,864 
    
 404,798 
    
 281,881 
 
Other Operation
    
 79,764 
    
 72,685 
    
 158,672 
    
 147,004 
 
Maintenance
    
 58,560 
    
 37,830 
    
 157,946 
    
 84,165 
 
Depreciation and Amortization
    
 83,240 
    
 85,139 
    
 171,143 
    
 165,552 
 
Taxes Other Than Income Taxes
    
 28,004 
    
 24,995 
    
 55,404 
    
 51,957 
 
TOTAL EXPENSES
    
 654,432 
    
 573,035 
    
 1,441,366 
    
 1,209,321 
                           
 
OPERATING INCOME
    
 92,072 
    
 143,426 
    
 256,632 
    
 312,616 
                           
 
Other Income (Expense):
                        
 
Interest Income
    
 1,469 
    
 359 
    
 1,800 
    
 702 
 
Carrying Costs Income
    
 3,133 
    
 5,467 
    
 3,236 
    
 13,252 
 
Allowance for Equity Funds Used During Construction
    
 1,213 
    
 4 
    
 1,983 
    
 517 
 
Interest Expense
    
 (48,128)
    
 (51,945)
    
 (96,332)
    
 (103,252)
                           
 
INCOME BEFORE INCOME TAX EXPENSE
    
 49,759 
    
 97,311 
    
 167,319 
    
 223,835 
                           
 
Income Tax Expense
    
 19,897 
    
 34,979 
    
 66,909 
    
 86,192 
                           
 
NET INCOME
  
$
 29,862 
  
$
 62,332 
  
$
 100,410 
  
$
 137,643 
                           
 
The common stock of APCo is wholly-owned by AEP.
   
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
92
 


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
Net Income
  
$
 29,862 
  
$
 62,332 
  
$
 100,410 
  
$
 137,643 
                           
OTHER COMPREHENSIVE INCOME, NET OF TAXES
                        
Cash Flow Hedges, Net of Tax of $48 and $305 for the Three Months Ended
                        
 
June 30, 2013 and 2012, Respectively, and $725 and $15 for the Six
                        
 
Months Ended June 30, 2013 and 2012, Respectively
    
 89 
    
 566 
    
 1,347 
    
 27 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $193
                        
 
and $484 for the Three Months Ended June 30, 2013 and 2012,
                        
 
Respectively, and $386 and $969 for the Six Months Ended
                        
 
June 30, 2013 and 2012, Respectively
    
 358 
    
 899 
    
 716 
    
 1,799 
                           
TOTAL OTHER COMPREHENSIVE INCOME
    
 447 
    
 1,465 
    
 2,063 
    
 1,826 
                           
TOTAL COMPREHENSIVE INCOME
  
$
 30,309 
  
$
 63,797 
  
$
 102,473 
  
$
 139,469 
                           
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
93
 


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
                                     
                           
Accumulated
    
                           
Other
    
         
Common
  
Paid-in
  
Retained
  
Comprehensive
    
         
Stock
  
Capital
  
Earnings
  
Income (Loss)
  
Total
TOTAL COMMON SHAREHOLDER'S EQUITY –
                              
 
DECEMBER 31, 2011
  
$
 260,458 
  
$
 1,573,752 
  
$
 1,160,747 
  
$
 (58,543)
  
$
 2,936,414 
                                     
Common Stock Dividends
                
 (100,000)
          
 (100,000)
Net Income
                
 137,643 
          
 137,643 
Other Comprehensive Income
                      
 1,826 
    
 1,826 
TOTAL COMMON SHAREHOLDER'S EQUITY –
                              
 
JUNE 30, 2012
  
$
 260,458 
  
$
 1,573,752 
  
$
 1,198,390 
  
$
 (56,717)
  
$
 2,975,883 
                                     
TOTAL COMMON SHAREHOLDER'S EQUITY –
                              
 
DECEMBER 31, 2012
  
$
 260,458 
  
$
 1,573,752 
  
$
 1,248,250 
  
$
 (29,898)
  
$
 3,052,562 
                                     
Common Stock Dividends
                
 (90,000)
          
 (90,000)
Net Income
                
 100,410 
          
 100,410 
Other Comprehensive Income
                      
 2,063 
    
 2,063 
TOTAL COMMON SHAREHOLDER'S EQUITY –
                              
 
JUNE 30, 2013
  
$
 260,458 
  
$
 1,573,752 
  
$
 1,258,660 
  
$
 (27,835)
  
$
 3,065,035 
                                     
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.
      

 
94
 


 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
ASSETS
 
June 30, 2013 and December 31, 2012
 
(in thousands)
 
(Unaudited)
   
         
June 30,
  
December 31,
     
2013 
  
2012 
 
CURRENT ASSETS
            
 
Cash and Cash Equivalents
  
$
 2,735 
  
$
 3,576 
 
Advances to Affiliates
    
 23,303 
    
 23,024 
 
Accounts Receivable:
            
   
Customers
    
 145,730 
    
 158,380 
   
Affiliated Companies
    
 58,353 
    
 96,213 
   
Accrued Unbilled Revenues
    
 44,839 
    
 70,825 
   
Miscellaneous
    
 2,177 
    
 1,344 
   
Allowance for Uncollectible Accounts
    
 (2,656)
    
 (6,087)
     
Total Accounts Receivable
    
 248,443 
    
 320,675 
 
Fuel
    
 218,577 
    
 185,813 
 
Materials and Supplies
    
 108,522 
    
 105,208 
 
Risk Management Assets
    
 28,520 
    
 30,960 
 
Accrued Tax Benefits
    
 37,354 
    
 50,032 
 
Regulatory Asset for Under-Recovered Fuel Costs
    
 62,849 
    
 74,906 
 
Prepayments and Other Current Assets
    
 16,262 
    
 18,690 
 
TOTAL CURRENT ASSETS
    
 746,565 
    
 812,884 
               
 
PROPERTY, PLANT AND EQUIPMENT
            
 
Electric:
            
   
Generation
    
 5,678,562 
    
 5,632,665 
   
Transmission
    
 2,053,457 
    
 2,042,144 
   
Distribution
    
 3,049,503 
    
 2,991,898 
 
Other Property, Plant and Equipment
    
 380,863 
    
 373,327 
 
Construction Work in Progress
    
 241,215 
    
 266,247 
 
Total Property, Plant and Equipment
    
 11,403,600 
    
 11,306,281 
 
Accumulated Depreciation and Amortization
    
 3,263,771 
    
 3,196,639 
 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    
 8,139,829 
    
 8,109,642 
                   
 
OTHER NONCURRENT ASSETS
            
 
Regulatory Assets
    
 1,364,541 
    
 1,435,704 
 
Long-term Risk Management Assets
    
 23,608 
    
 34,360 
 
Deferred Charges and Other Noncurrent Assets
    
 109,465 
    
 115,078 
 
TOTAL OTHER NONCURRENT ASSETS
    
 1,497,614 
    
 1,585,142 
               
 
TOTAL ASSETS
  
$
 10,384,008 
  
$
 10,507,668 
               
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.
                   
                   
                   
                   
                   
 
 
95
 
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
June 30, 2013 and December 31, 2012
 
(Unaudited)
   
         
June 30,
  
December 31,
     
2013 
  
2012 
       
(in thousands)
 
CURRENT LIABILITIES
            
 
Advances from Affiliates
  
$
 87,783 
  
$
 173,965 
 
Accounts Payable:
            
   
General
    
 150,500 
    
 195,203 
   
Affiliated Companies
    
 99,096 
    
 137,088 
 
Long-term Debt Due Within One Year – Nonaffiliated
    
 574,681 
    
 574,679 
 
Risk Management Liabilities
    
 13,397 
    
 16,698 
 
Customer Deposits
    
 65,999 
    
 67,339 
 
Deferred Income Taxes
    
 8,388 
    
 11,715 
 
Accrued Taxes
    
 80,347 
    
 74,967 
 
Accrued Interest
    
 51,207 
    
 51,442 
 
Other Current Liabilities
    
 97,782 
    
 110,657 
 
TOTAL CURRENT LIABILITIES
    
 1,229,180 
    
 1,413,753 
               
 
NONCURRENT LIABILITIES
            
 
Long-term Debt – Nonaffiliated
    
 3,128,078 
    
 3,127,763 
 
Long-term Risk Management Liabilities
    
 14,007 
    
 18,476 
 
Deferred Income Taxes
    
 1,968,214 
    
 1,928,683 
 
Regulatory Liabilities and Deferred Investment Tax Credits
    
 623,394 
    
 607,680 
 
Employee Benefits and Pension Obligations
    
 202,114 
    
 204,207 
 
Deferred Credits and Other Noncurrent Liabilities
    
 153,986 
    
 154,544 
 
TOTAL NONCURRENT LIABILITIES
    
 6,089,793 
    
 6,041,353 
               
 
TOTAL LIABILITIES
    
 7,318,973 
    
 7,455,106 
               
 
Rate Matters (Note 3)
            
 
Commitments and Contingencies (Note 4)
            
               
 
COMMON SHAREHOLDER’S EQUITY
            
 
Common Stock – No Par Value:
            
   
Authorized – 30,000,000 Shares
            
   
Outstanding – 13,499,500 Shares
    
 260,458 
    
 260,458 
 
Paid-in Capital
    
 1,573,752 
    
 1,573,752 
 
Retained Earnings
    
 1,258,660 
    
 1,248,250 
 
Accumulated Other Comprehensive Income (Loss)
    
 (27,835)
    
 (29,898)
 
TOTAL COMMON SHAREHOLDER’S EQUITY
    
 3,065,035 
    
 3,052,562 
               
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
  
$
 10,384,008 
  
$
 10,507,668 
               
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
96
 

 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
 
         
Six Months Ended June 30,
   
2013 
  
2012 
OPERATING ACTIVITIES
            
Net Income
  
$
 100,410 
  
$
 137,643 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
            
   
Depreciation and Amortization
    
 171,143 
    
 165,552 
   
Deferred Income Taxes
    
 42,158 
    
 56,927 
   
Carrying Costs Income
    
 (3,236)
    
 (13,252)
   
Allowance for Equity Funds Used During Construction
    
 (1,983)
    
 (517)
   
Mark-to-Market of Risk Management Contracts
    
 6,765 
    
 (2,323)
   
Fuel Over/Under-Recovery, Net
    
 25,919 
    
 26,417 
   
Change in Other Noncurrent Assets
    
 35,219 
    
 (16,708)
   
Change in Other Noncurrent Liabilities
    
 9,670 
    
 18,266 
   
Changes in Certain Components of Working Capital:
            
     
Accounts Receivable, Net
    
 73,280 
    
 103,680 
     
Fuel, Materials and Supplies
    
 (36,078)
    
 (54,954)
     
Accounts Payable
    
 (57,034)
    
 (43,538)
     
Accrued Taxes, Net
    
 18,058 
    
 30,032 
     
Other Current Assets
    
 1,621 
    
 2,579 
     
Other Current Liabilities
    
 (14,440)
    
 (15,880)
Net Cash Flows from Operating Activities
    
 371,472 
    
 393,924 
             
INVESTING ACTIVITIES
            
Construction Expenditures
    
 (194,200)
    
 (212,959)
Change in Advances to Affiliates, Net
    
 (279)
    
 (565)
Other Investing Activities
    
 (108)
    
 3,158 
Net Cash Flows Used for Investing Activities
    
 (194,587)
    
 (210,366)
             
FINANCING ACTIVITIES
            
Change in Advances from Affiliates, Net
    
 (86,182)
    
 (31,260)
Retirement of Long-term Debt – Nonaffiliated
    
 (14)
    
 (49,512)
Principal Payments for Capital Lease Obligations
    
 (2,623)
    
 (3,258)
Dividends Paid on Common Stock
    
 (90,000)
    
 (100,000)
Other Financing Activities
    
 1,093 
    
 264 
Net Cash Flows Used for Financing Activities
    
 (177,726)
    
 (183,766)
             
Net Decrease in Cash and Cash Equivalents
    
 (841)
    
 (208)
Cash and Cash Equivalents at Beginning of Period
    
 3,576 
    
 2,317 
Cash and Cash Equivalents at End of Period
  
$
 2,735 
  
$
 2,109 
             
SUPPLEMENTARY INFORMATION
            
Cash Paid for Interest, Net of Capitalized Amounts
  
$
 92,994 
  
$
 100,319 
Net Cash Paid (Received) for Income Taxes
    
 425 
    
 (10,090)
Noncash Acquisitions Under Capital Leases
    
 2,422 
    
 1,265 
Construction Expenditures Included in Current Liabilities as of June 30,
    
 34,114 
    
 30,439 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
97
 

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

The condensed notes to APCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to APCo.

 
Page
 
Number
   
Significant Accounting Matters
   154
Comprehensive Income
   154
Rate Matters
   168
Commitments, Guarantees and Contingencies
   178
Benefit Plans
   183
Business Segments
   185
Derivatives and Hedging
   186
Fair Value Measurements
   199
Income Taxes
   211
Financing Activities
   212
Variable Interest Entities
   216
Sustainable Cost Reductions
   219

 
98
 
 
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES


 
99
 

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

EXECUTIVE OVERVIEW

Regulatory Activity

Termination of Interconnection Agreement

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

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

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%.  In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates to $92 million.  In March 2013, the Indiana Office of Utility Consumer Counselor filed an appeal of the order with the Indiana Court of Appeals.  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.

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 of its units at the Rockport Plant with a Dry Sorbent Injection system.  The estimated cost in the application was $285 million, excluding AFUDC, of which I&M’s ownership share is $142 million.  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 direct ownership share of $129 million.  Hearings at the IURC are scheduled for August 2013.  A decision is expected by November 2013.  As of June 30, 2013, I&M has incurred costs of $39 million related to the CCT Project, including AFUDC.  If I&M is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows.  See the “Rockport Plant Clean Coal Technology Project (CCT Project)” section of Note 3.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of June 30, 2013, I&M has incurred $240 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items which the IURC stated could be sought for recovery in a base rate case.  I&M was granted recovery through an LCM rider which will be determined by a mid-September 2013 proceeding and semi-annual proceedings thereafter.  The IURC authorized deferral accounting for I&M’s incurred project costs effective January 2012 to the extent such costs are not reflected in its rates.
 
100
 

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON.  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.

Litigation and Environmental Issues

In the ordinary course of business, I&M is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 153.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 220 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
                      
                           
KWh Sales/Degree Days
                      
                           
Summary of KWh Energy Sales
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
 
2013 
  
2012 
  
2013 
  
2012 
     
(in millions of KWhs)
Retail:
                      
 
Residential
  
 1,152 
    
 1,217 
    
 2,878 
    
 2,786 
 
Commercial
  
 1,197 
    
 1,290 
    
 2,385 
    
 2,456 
 
Industrial
  
 1,884 
    
 1,964 
    
 3,697 
    
 3,797 
 
Miscellaneous
  
 15 
    
 15 
    
 35 
    
 38 
Total Retail (a)
  
 4,248 
    
 4,486 
    
 8,995 
    
 9,077 
                       
Wholesale
  
 2,251 
    
 2,068 
    
 4,831 
    
 4,029 
                       
Total KWhs
  
 6,499 
    
 6,554 
    
 13,826 
    
 13,106 
                           
(a)
Represents energy delivered to distribution customers.

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

 
Summary of Heating and Cooling Degree Days
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
     
(in degree days)
 
Actual - Heating (a)
  
 263 
    
 163 
    
 2,551 
    
 1,784 
 
Normal - Heating (b)
  
 230 
    
 235 
    
 2,385 
    
 2,420 
                           
 
Actual - Cooling (c)
  
 278 
    
 369 
    
 278 
    
 398 
 
Normal - Cooling (b)
  
 260 
    
 256 
    
 262 
    
 257 
                           
 
(a)
Eastern Region heating degree days are calculated on a 55 degree temperature base.
 
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
 
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.

 
101
 


Second Quarter of 2013 Compared to Second Quarter of 2012
                 
 
Reconciliation of Second Quarter of 2012 to Second Quarter of 2013
 
Net Income
 
(in millions)
                 
 
Second Quarter of 2012
        
$
 30 
                 
 
Changes in Gross Margin:
            
 
Retail Margins
          
 13 
 
FERC Municipals and Cooperatives
          
 21 
 
Off-system Sales
          
 (3)
 
Transmission Revenues
          
 (4)
 
Other Revenues
          
 (1)
 
Total Change in Gross Margin
          
 26 
               
 
Changes in Expenses and Other:
            
 
Other Operation and Maintenance
          
 (1)
 
Depreciation and Amortization
          
 (8)
 
Taxes Other Than Income Taxes
          
 (4)
 
Other Income
          
 5 
 
Total Change in Expenses and Other
          
 (8)
                 
 
Income Tax Expense
          
 (7)
                 
 
Second Quarter of 2013
        
$
 41 

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 $13 million primarily due to the following:
   
·
A $24 million increase due to rate increases in Indiana effective March 2013, higher PJM revenue and higher Indiana Demand Side Management (DSM) revenue.  The PJM and DSM increases were partially offset in expense items below.
   
These increases were partially offset by:
   
·
An $8 million decrease due to lower weather-normalized sales.
   
·
A $4 million decrease in weather-related usage primarily due to a decrease in cooling degree days.
 
·
Margins from FERC Municipal and Cooperatives increased $21 million primarily due to the annual true-up adjustment of formula rates to actual costs.
 
·
Margins from Off-system Sales decreased $3 million primarily due to lower PJM capacity revenues and reduced trading and marketing margins.
 
·
Transmission Revenues decreased $4 million primarily due to increased PJM costs.

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

 
·
Depreciation and Amortization expenses increased $8 million primarily due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant’s estimated life approved in Indiana effective March 2013.  The majority of the increase in depreciation for Tanners Creek Plant’s life is offset within Gross Margin.
 
·
Taxes Other Than Income Taxes expenses increased $4 million primarily due to property tax increases.
 
·
Other Income increased $5 million primarily due to an increase in equity AFUDC.
 
·
Income Tax Expense increased $7 million primarily due to an increase in pretax book income.

 
102
 


Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
                     
 
Reconciliation of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2013
 
Net Income
 
(in millions)
                     
   
Six Months Ended June 30, 2012
        
$
 69 
  
                     
   
Changes in Gross Margin:
              
   
Retail Margins
          
 37 
  
   
FERC Municipals and Cooperatives
          
 20 
  
   
Off-system Sales
          
 (4)
  
   
Transmission Revenues
          
 (4)
  
   
Other Revenues
          
 2 
  
   
Total Change in Gross Margin
          
 51 
  
                   
   
Changes in Expenses and Other:
              
   
Other Operation and Maintenance
          
 (14)
  
   
Depreciation and Amortization
          
 (15)
  
   
Taxes Other Than Income Taxes
          
 (4)
  
   
Other Income
          
 8 
  
   
Interest Expense
          
 1 
  
   
Total Change in Expenses and Other
          
 (24)
  
                     
   
Income Tax Expense
          
 (12)
  
                     
   
Six Months Ended June 30, 2013
        
$
 84 
  

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 $37 million primarily due to the following:
   
·
A $33 million increase due to rate increases in Indiana effective March 2013, higher PJM revenue and higher Indiana Demand Side Management (DSM) revenue.  The PJM and DSM increases were partially offset in expense items below.
 
·
Margins from FERC Municipal and Cooperatives increased $20 million primarily due to the annual true-up adjustment of formula rates to actual costs.
 
·
Margins from Off-system Sales decreased $4 million primarily due to lower PJM capacity revenues and reduced trading and marketing margins.
 
·
Transmission Revenues decreased $4 million primarily due to increased PJM costs.

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

 
·
Other Operation and Maintenance expenses increased $14 million primarily due to the following:
   
·
An $8 million increase in steam maintenance expenses primarily due to Rockport Plant and Tanners Creek Plant outages in the first quarter of 2013.
   
·
A $7 million increase in transmission expenses primarily due to increased PJM costs.
   
·
A $4 million increase in customer service costs primarily due to higher DSM expenses.  The increase in DSM expenses was offset by a corresponding increase in Retail Margins discussed above.
   
These increases were partially offset by:
   
·
A $5 million decrease in administrative and general operation expenses.
 
·
Depreciation and Amortization expenses increased $15 million primarily due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant’s estimated life approved in Michigan effective April 2012 and in Indiana effective March 2013.  The majority of the increase in depreciation for Tanners Creek Plant’s life is offset within Gross Margin.
 
 
103
 
 
·
Taxes Other Than Income Taxes expenses increased $4 million primarily due to property tax increases.
 
·
Other Income increased $8 million primarily due to an increase in equity AFUDC.
 
·
Income Tax Expense increased $12 million primarily due to an increase in pretax book income and other book/tax differences which are accounted for on a flow-through basis.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 220 for a discussion of accounting pronouncements.

 
104
 

 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
For the Three and Six Months Ended June 30, 2013 and 2012
 
(in thousands)
 
(Unaudited)
   
       
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
 
REVENUES
                      
 
Electric Generation, Transmission and Distribution
  
$
 490,301 
  
$
 435,965 
  
$
 980,904 
  
$
 871,992 
 
Sales to AEP Affiliates
    
 31,335 
    
 45,728 
    
 86,312 
    
 121,643 
 
Other Revenues – Affiliated
    
 26,815 
    
 29,052 
    
 62,640 
    
 59,763 
 
Other Revenues – Nonaffiliated
    
 1,050 
    
 131 
    
 3,038 
    
 3,685 
 
TOTAL REVENUES
    
 549,501 
    
 510,876 
    
 1,132,894 
    
 1,057,083 
                             
 
EXPENSES
                        
 
Fuel and Other Consumables Used for Electric Generation
    
 85,030 
    
 96,715 
    
 189,895 
    
 209,085 
 
Purchased Electricity for Resale
    
 36,814 
    
 29,488 
    
 78,626 
    
 65,398 
 
Purchased Electricity from AEP Affiliates
    
 99,547 
    
 82,188 
    
 200,923 
    
 170,141 
 
Other Operation
    
 132,478 
    
 134,274 
    
 277,716 
    
 269,490 
 
Maintenance
    
 50,238 
    
 47,244 
    
 95,752 
    
 89,509 
 
Depreciation and Amortization
    
 45,696 
    
 37,560 
    
 86,598 
    
 71,539 
 
Taxes Other Than Income Taxes
    
 22,165 
    
 18,604 
    
 44,621 
    
 40,793 
 
TOTAL EXPENSES
    
 471,968 
    
 446,073 
    
 974,131 
    
 915,955 
                             
 
OPERATING INCOME
    
 77,533 
    
 64,803 
    
 158,763 
    
 141,128 
                             
 
Other Income (Expense):
                        
 
Interest Income
    
 2,662 
    
 524 
    
 4,717 
    
 1,775 
 
Allowance for Equity Funds Used During Construction
    
 4,881 
    
 2,324 
    
 10,527 
    
 5,335 
 
Interest Expense
    
 (24,436)
    
 (25,373)
    
 (48,647)
    
 (50,426)
                             
 
INCOME BEFORE INCOME TAX EXPENSE
    
 60,640 
    
 42,278 
    
 125,360 
    
 97,812 
                             
 
Income Tax Expense
    
 19,886 
    
 12,468 
    
 41,149 
    
 28,781 
                             
 
NET INCOME
  
$
 40,754 
  
$
 29,810 
  
$
 84,211 
  
$
 69,031 
                             
 
The common stock of I&M is wholly-owned by AEP.
                        
                             
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
105
 


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
Net Income
  
$
 40,754 
  
$
 29,810 
  
$
 84,211 
  
$
 69,031 
                           
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                        
Cash Flow Hedges, Net of Tax of $172 and $4,002 for the Three Months Ended
                        
 
June 30, 2013 and 2012, Respectively, and $1,854 and $2,680 for the
                        
 
Six Months Ended June 30, 2013 and 2012, Respectively
    
 321 
    
 (7,433)
    
 3,444 
    
 (4,977)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $95
                        
 
and $150 for the Three Months Ended June 30, 2013 and 2012,
                        
 
Respectively, and $189 and $300 for the Six Months Ended June 30, 2013
                        
 
and 2012, Respectively
    
 175 
    
 278 
    
 351 
    
 557 
                           
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
    
 496 
    
 (7,155)
    
 3,795 
    
 (4,420)
                           
TOTAL COMPREHENSIVE INCOME
  
$
 41,250 
  
$
 22,655 
  
$
 88,006 
  
$
 64,611 
                           
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
106
 


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
 
                     
Accumulated
    
                     
Other
    
   
Common
  
Paid-in
  
Retained
  
Comprehensive
    
         
Stock
  
Capital
  
Earnings
  
Income (Loss)
  
Total
TOTAL COMMON SHAREHOLDER'S
                              
 
EQUITY – DECEMBER 31, 2011
  
$
 56,584 
  
$
 980,896 
  
$
 751,721 
  
$
 (28,221)
  
$
 1,760,980 
                               
Common Stock Dividends
                
 (25,000)
          
 (25,000)
Net Income
                
 69,031 
          
 69,031 
Other Comprehensive Loss
                      
 (4,420)
    
 (4,420)
TOTAL COMMON SHAREHOLDER'S
                              
 
EQUITY – JUNE 30, 2012
  
$
 56,584 
  
$
 980,896 
  
$
 795,752 
  
$
 (32,641)
  
$
 1,800,591 
                               
TOTAL COMMON SHAREHOLDER'S
                              
 
EQUITY – DECEMBER 31, 2012
  
$
 56,584 
  
$
 980,896 
  
$
 795,178 
  
$
 (28,883)
  
$
 1,803,775 
                               
Common Stock Dividends
                
 (25,000)
          
 (25,000)
Net Income
                
 84,211 
          
 84,211 
Other Comprehensive Income
                      
 3,795 
    
 3,795 
TOTAL COMMON SHAREHOLDER'S
                              
 
EQUITY – JUNE 30, 2013
  
$
 56,584 
  
$
 980,896 
  
$
 854,389 
  
$
 (25,088)
  
$
 1,866,781 
                               
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
107
 


 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
ASSETS
 
June 30, 2013 and December 31, 2012
 
(in thousands)
 
(Unaudited)
                   
         
June 30,
  
December 31,
     
2013 
  
2012 
 
CURRENT ASSETS
            
 
Cash and Cash Equivalents
  
$
 1,014 
  
$
 1,562 
 
Advances to Affiliates
    
 273,117 
    
 116,977 
 
Accounts Receivable:
            
   
Customers
    
 79,501 
    
 61,776 
   
Affiliated Companies
    
 58,494 
    
 79,886 
   
Accrued Unbilled Revenues
    
 11,207 
    
 11,218 
   
Miscellaneous
    
 6,400 
    
 12,260 
   
Allowance for Uncollectible Accounts
    
 (67)
    
 (229)
     
Total Accounts Receivable
    
 155,535 
    
 164,911 
 
Fuel
    
 74,818 
    
 53,406 
 
Materials and Supplies
    
 191,195 
    
 195,147 
 
Risk Management Assets
    
 19,599 
    
 26,974 
 
Deferred Cook Plant Fire Costs
    
 - 
    
 80,000 
 
Prepayments and Other Current Assets
    
 71,782 
    
 83,270 
 
TOTAL CURRENT ASSETS
    
 787,060 
    
 722,247 
               
 
PROPERTY, PLANT AND EQUIPMENT
            
 
Electric:
            
   
Generation
    
 4,130,327 
    
 4,062,733 
   
Transmission
    
 1,298,743 
    
 1,278,236 
   
Distribution
    
 1,580,709 
    
 1,553,358 
 
Other Property, Plant and Equipment (Including Nuclear Fuel and Coal Mining)
    
 752,084 
    
 725,313 
 
Construction Work in Progress
    
 370,384 
    
 341,063 
 
Total Property, Plant and Equipment
    
 8,132,247 
    
 7,960,703 
 
Accumulated Depreciation, Depletion and Amortization
    
 3,269,566 
    
 3,232,135 
 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    
 4,862,681 
    
 4,728,568 
               
 
OTHER NONCURRENT ASSETS
            
 
Regulatory Assets
    
 564,163 
    
 540,019 
 
Spent Nuclear Fuel and Decommissioning Trusts
    
 1,791,394 
    
 1,705,772 
 
Long-term Risk Management Assets
    
 16,315 
    
 23,569 
 
Deferred Charges and Other Noncurrent Assets
    
 117,327 
    
 111,364 
 
TOTAL OTHER NONCURRENT ASSETS
    
 2,489,199 
    
 2,380,724 
               
 
TOTAL ASSETS
  
$
 8,138,940 
  
$
 7,831,539 
               
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.
 
 
108
 
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
June 30, 2013 and December 31, 2012
 
(dollars in thousands)
 
(Unaudited)
   
         
June 30,
  
December 31,
         
2013 
  
2012 
 
CURRENT LIABILITIES
            
 
Accounts Payable:
            
   
General
  
$
 143,935 
  
$
 208,701 
   
Affiliated Companies
    
 59,793 
    
 104,631 
 
Long-term Debt Due Within One Year – Nonaffiliated
            
   
(June 30, 2013 and December 31, 2012 Amounts Include $141,869 and
            
   
$119,890, Respectively, Related to DCC Fuel)
    
 228,748 
    
 203,953 
 
Risk Management Liabilities
    
 9,387 
    
 31,517 
 
Customer Deposits
    
 29,794 
    
 31,142 
 
Accrued Taxes
    
 66,786 
    
 67,675 
 
Accrued Interest
    
 28,745 
    
 26,859 
 
Other Current Liabilities
    
 102,011 
    
 122,053 
 
TOTAL CURRENT LIABILITIES
    
 669,199 
    
 796,531 
               
 
NONCURRENT LIABILITIES
            
 
Long-term Debt – Nonaffiliated
    
 2,076,444 
    
 1,853,713 
 
Long-term Risk Management Liabilities
    
 10,020 
    
 13,898 
 
Deferred Income Taxes
    
 1,090,509 
    
 1,019,160 
 
Regulatory Liabilities and Deferred Investment Tax Credits
    
 990,801 
    
 948,292 
 
Asset Retirement Obligations
    
 1,233,640 
    
 1,192,313 
 
Deferred Credits and Other Noncurrent Liabilities
    
 201,546 
    
 203,857 
 
TOTAL NONCURRENT LIABILITIES
    
 5,602,960 
    
 5,231,233 
               
 
TOTAL LIABILITIES
    
 6,272,159 
    
 6,027,764 
               
 
Rate Matters (Note 3)
            
 
Commitments and Contingencies (Note 4)
            
               
 
COMMON SHAREHOLDER’S EQUITY
            
 
Common Stock – No Par Value:
            
   
Authorized – 2,500,000 Shares
            
   
Outstanding – 1,400,000 Shares
    
 56,584 
    
 56,584 
 
Paid-in Capital
    
 980,896 
    
 980,896 
 
Retained Earnings
    
 854,389 
    
 795,178 
 
Accumulated Other Comprehensive Income (Loss)
    
 (25,088)
    
 (28,883)
 
TOTAL COMMON SHAREHOLDER’S EQUITY
    
 1,866,781 
    
 1,803,775 
               
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
  
$
 8,138,940 
  
$
 7,831,539 
       
 
    
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
109
 


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
 
         
Six Months Ended June 30,
   
2013 
  
2012 
OPERATING ACTIVITIES
            
Net Income
  
$
 84,211 
  
$
 69,031 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
            
   
Depreciation and Amortization
    
 86,598 
    
 71,539 
   
Deferred Income Taxes
    
 51,234 
    
 40,899 
   
Deferral of Incremental Nuclear Refueling Outage Expenses, Net
    
 (18,283)
    
 (9,163)
   
Allowance for Equity Funds Used During Construction
    
 (10,527)
    
 (5,335)
   
Mark-to-Market of Risk Management Contracts
    
 9,096 
    
 (2,798)
   
Amortization of Nuclear Fuel
    
 62,625 
    
 64,228 
   
Fuel Over/Under-Recovery, Net
    
 (1,796)
    
 (2,650)
   
Change in Other Noncurrent Assets
    
 (2,690)
    
 6,849 
   
Change in Other Noncurrent Liabilities
    
 3,599 
    
 42,793 
   
Changes in Certain Components of Working Capital:
            
     
Accounts Receivable, Net
    
 9,376 
    
 31,614 
     
Fuel, Materials and Supplies
    
 (17,460)
    
 (8,475)
     
Accounts Payable
    
 (48,048)
    
 (33,573)
     
Accrued Taxes, Net
    
 10,250 
    
 19,642 
     
Other Current Assets
    
 12,209 
    
 (9,183)
     
Other Current Liabilities
    
 (16,764)
    
 (26,557)
Net Cash Flows from Operating Activities
    
 213,630 
    
 248,861 
             
INVESTING ACTIVITIES
            
Construction Expenditures
    
 (267,201)
    
 (137,473)
Change in Advances to Affiliates, Net
    
 (156,140)
    
 (142,752)
Purchases of Investment Securities
    
 (411,769)
    
 (544,981)
Sales of Investment Securities
    
 385,942 
    
 516,579 
Acquisitions of Nuclear Fuel
    
 (58,900)
    
 (11,263)
Insurance Proceeds Related to Cook Plant Fire
    
 72,000 
    
 - 
Other Investing Activities
    
 3,898 
    
 26,692 
Net Cash Flows Used for Investing Activities
    
 (432,170)
    
 (293,198)
             
FINANCING ACTIVITIES
            
Issuance of Long-term Debt – Nonaffiliated
    
 348,899 
    
 128,533 
Retirement of Long-term Debt – Nonaffiliated
    
 (103,793)
    
 (55,995)
Principal Payments for Capital Lease Obligations
    
 (2,791)
    
 (3,490)
Dividends Paid on Common Stock
    
 (25,000)
    
 (25,000)
Other Financing Activities
    
 677 
    
 167 
Net Cash Flows from Financing Activities
    
 217,992 
    
 44,215 
             
Net Decrease in Cash and Cash Equivalents
    
 (548)
    
 (122)
Cash and Cash Equivalents at Beginning of Period
    
 1,562 
    
 1,020 
Cash and Cash Equivalents at End of Period
  
$
 1,014 
  
$
 898 
             
SUPPLEMENTARY INFORMATION
            
Cash Paid for Interest, Net of Capitalized Amounts
  
$
 44,165 
  
$
 48,565 
Net Cash Paid (Received) for Income Taxes
    
 (27,608)
    
 (31,921)
Noncash Acquisitions Under Capital Leases
    
 1,888 
    
 4,341 
Construction Expenditures Included in Current Liabilities as of June 30,
    
 44,060 
    
 26,509 
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,
    
 41,086 
    
 14 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
110
 

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

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

 
Page
 
Number
   
Significant Accounting Matters
   154
Comprehensive Income
   154
Rate Matters
   168
Commitments, Guarantees and Contingencies
   178
Benefit Plans
   183
Business Segments
   185
Derivatives and Hedging
   186
Fair Value Measurements
   199
Income Taxes
   211
Financing Activities
   212
Variable Interest Entities
   216
Sustainable Cost Reductions
   219

 
111
 

 
OHIO POWER COMPANY AND SUBSIDIARY



 
112
 

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

EXECUTIVE OVERVIEW

Ohio Customer Choice

In OPCo’s service territory, various CRES providers are targeting retail customers by offering alternative generation service.  The reduction in gross margin as a result of customer switching in Ohio is partially offset by (a) collection of capacity revenues from CRES providers, (b) off-system sales, (c) deferral of unrecovered capacity costs and (d) Retail Stability Rider collections.

Regulatory Activity

Ohio Electric Security Plan Filing

2009 – 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover OPCo’s deferred fuel costs in rates beginning September 2012.  As of June 30, 2013, OPCo’s net deferred fuel balance was $484 million, excluding unrecognized equity carrying costs.  Decisions from the Supreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance.

June 2012 – May 2015 Ohio ESP Including Capacity Charge

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

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The RPM price is approximately $33/MW day through May 2014.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.  As of June 30, 2013, OPCo’s incurred deferred capacity costs balance was $171 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 is expected to provide approximately $500 million of revenue over the ESP period and will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the deferred capacity costs.

In 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 $160 million through May 2015. 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. 
 
113
 

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

Corporate Separation, Plant Transfers and Termination of Interconnection Agreement

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets at net book value (NBV) to AEPGenCo.  AEPGenCo will also assume the associated generation liabilities.  In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.

Also in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations.  The filings requested approval to transfer at NBV approximately 9,200 MW of OPCo-owned generation assets to AEPGenCo.  The AEP East Companies also requested FERC approval to transfer at NBV OPCo’s current two-thirds ownership in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests.  In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AEPGenCo and the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo, to be effective using the requested date of December 31, 2013.  In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo.  OPCo has contested the petition for rehearing, which remains pending before the FERC.

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

Significantly Excessive Earnings Test

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings.  OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO-ordered SEET refund.  OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis.  Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in 2012 for OPCo.  Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo.  Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition.  See “Ohio Electric Security Plan Filing” section of Note 3.

Securitization of Regulatory Assets

In March 2013, the PUCO approved OPCo’s request to securitize the Deferred Asset Recovery Rider (DARR) balance.  As of June 30, 2013, OPCo’s DARR balance was $268 million, including $126 million of unrecognized equity carrying costs.  The DARR is being recovered through 2018 by a non-bypassable rider.  Once the securitization bonds are issued, the DARR will cease and will be replaced by the Deferred Asset Phase-in Rider, which will recover the securitized asset over a period not to exceed eight years.  The securitization bonds are expected to be issued in the third quarter of 2013. 
 
Muskingum River Plant, Unit 5 Impairment
 
Muskingum River Plant, Unit 5 (MR5) had options under a consent decree to cease burning coal and retire in 2015 or cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017.  In the second quarter of 2013, management re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project which would have extended the useful life of MR5 is remote.  
 
 
114
 
As a result, in the second quarter of 2013, OPCo completed an impairment analysis and recorded a $154 million ($99 million, net of tax) pretax impairment charge for OPCo’s net book value of MR5.  Management expects to retire the plant in 2015.  See “Muskingum River Plant, Unit 5” section of Note 5.

Litigation and Environmental Issues

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 153.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 220 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
                      
                           
KWh Sales/Degree Days
                      
                           
Summary of KWh Energy Sales
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
 
2013 
  
2012 
  
2013 
  
2012 
     
(in millions of KWhs)
Retail:
                      
 
Residential
  
 3,000 
    
 3,002 
    
 7,264 
    
 6,881 
 
Commercial
  
 3,506 
    
 3,582 
    
 6,892 
    
 6,818 
 
Industrial
  
 4,203 
    
 4,799 
    
 8,285 
    
 9,520 
 
Miscellaneous
  
 27 
    
 27 
    
 62 
    
 58 
Total Retail (a)
  
 10,736 
    
 11,410 
    
 22,503 
    
 23,277 
                       
Wholesale
  
 2,417 
    
 2,798 
    
 5,461 
    
 5,304 
                       
Total KWhs
  
 13,153 
    
 14,208 
    
 27,964 
    
 28,581 
                           
(a)
Represents energy delivered to distribution customers.

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

 
Summary of Heating and Cooling Degree Days
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
     
(in degree days)
 
Actual - Heating (a)
  
 193 
    
 146 
    
 2,164 
    
 1,543 
 
Normal - Heating (b)
  
 190 
    
 195 
    
 2,075 
    
 2,112 
                           
 
Actual - Cooling (c)
  
 346 
    
 401 
    
 346 
    
 428 
 
Normal - Cooling (b)
  
 277 
    
 270 
    
 280 
    
 273 
                           
 
(a)
Eastern Region heating degree days are calculated on a 55 degree temperature base.
 
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
 
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.

 
115
 


Second Quarter of 2013 Compared to Second Quarter of 2012
                 
Reconciliation of Second Quarter of 2012 to Second Quarter of 2013
Net Income
(in millions)
                 
 
Second Quarter of 2012
        
$
 101 
                 
 
Changes in Gross Margin:
            
 
Retail Margins
          
 (4)
 
Off-system Sales
          
 (42)
 
Transmission Revenues
          
 5 
 
Total Change in Gross Margin
          
 (41)
               
 
Changes in Expenses and Other:
            
 
Other Operation and Maintenance
          
 26 
 
Asset Impairments and Other Related Charges
          
 (154)
 
Depreciation and Amortization
          
 35 
 
Taxes Other Than Income Taxes
          
 (2)
 
Interest Expense
          
 6 
 
Total Change in Expenses and Other
          
 (89)
                 
 
Income Tax Expense
          
 50 
                 
 
Second Quarter of 2013
        
$
 21 

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

 
·
Retail Margins decreased $4 million primarily due to the following:
   
·
A $66 million decrease attributable to customers switching to alternative CRES providers.  This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
   
·
A $35 million decrease due to the second quarter 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
   
·
An $8 million decrease due to lower sales to Buckeye Power, Inc. to provide backup energy under the Cardinal Station Agreement.
   
·
A $6 million decrease in weather-related usage primarily due to a 14% decrease in cooling degree days.
   
These decreases were partially offset by:
   
·
An $85 million increase in revenues associated with the Universal Service Fund (USF) surcharge, Retail Stability Rider, Deferred Asset Recovery Rider and Distribution Investment Recovery Rider.  The majority of these increases have corresponding increases in other expense items below.
   
·
A $26 million increase due to the deferral of consumables and purchased power as a result of the PUCO’s July 2012 approval of the capacity deferral mechanism.
 
·
Margins from Off-system Sales decreased $42 million 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. The decrease in CRES capacity revenues is partially offset in other expense items below.
 
·
Transmission Revenues increased $5 million primarily due to increased transmission revenues from customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers offsets lost revenues included in Retail Margins above.

 
116
 
Expenses and Other and Income Tax Expense changed between years as follows:

 
·
Other Operation and Maintenance expenses decreased $26 million primarily due to the following:
   
·
A $12 million decrease due to the deferral of capacity-related costs as a result of the PUCO's July 2012 approval of the capacity deferral mechanism.
   
·
A $12 million decrease in recoverable PJM expenses.
   
·
A $6 million decrease in advertising expenses.
   
·
A $3 million decrease due to expenses recorded in 2012 for the 2012 sustainable cost reductions program.
   
·
A $3 million decrease due to updated gridSMART rider allocation ratios between capital carrying charges and operations expense beginning in January 2013. This decrease was partially offset by a corresponding increase in Depreciation and Amortization.
   
These decreases were partially offset by:
   
·
A $19 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase was offset by a corresponding increase in Retail Margins above.
 
·
Asset Impairments and Other Related Charges increased $154 million due to the second quarter 2013 impairment of Muskingum River Plant, Unit 5.
 
·
Depreciation and Amortization expenses decreased $35 million primarily due to the following:
   
·
A $26 million decrease as a result of depreciation ceasing on certain generating plants that were impaired in November 2012.
   
·
A $15 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.
 
·
Interest Expense decreased $6 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
 
·
Income Tax Expense decreased $50 million primarily due to a decrease in pretax book income.

 
117
 


Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
                 
 
Reconciliation of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2013
 
Net Income
 
(in millions)
                 
 
Six Months Ended June 30, 2012
        
$
 252 
                 
 
Changes in Gross Margin:
            
 
Retail Margins
          
 (3)
 
Off-system Sales
          
 (74)
 
Transmission Revenues
          
 16 
 
Total Change in Gross Margin
          
 (61)
               
 
Changes in Expenses and Other:
            
 
Other Operation and Maintenance
          
 (22)
 
Asset Impairments and Other Related Charges
          
 (154)
 
Depreciation and Amortization
          
 76 
 
Interest Expense
          
 10 
 
Total Change in Expenses and Other
          
 (90)
                 
 
Income Tax Expense
          
 50 
                 
 
Six Months Ended June 30, 2013
        
$
 151 

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

 
·
Retail Margins decreased $3 million primarily due to the following:
   
·
A $153 million decrease attributable to customers switching to alternative CRES providers.  This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
   
·
A $35 million decrease due to the second quarter 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
   
·
A $15 million decrease due to lower sales to Buckeye Power, Inc. to provide backup energy under the Cardinal Station Agreement.
   
·
A $5 million decrease in capacity settlement revenues under the Interconnection Agreement.
   
These decreases were partially offset by:
   
·
A $146 million increase in revenues associated with the USF surcharge, Retail Stability Rider, Deferred Asset Recovery Rider and Distribution Investment Recovery Rider.  The majority of these increases have corresponding increases in other expense items below.
   
·
A $47 million increase due to the deferral of consumables and purchased power as a result of the PUCO’s July 2012 approval of the capacity deferral mechanism.
   
·
A $15 million increase in weather-related usage primarily due to a 40% increase in heating degree days.
 
·
Margins from Off-system Sales decreased $74 million 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, partially offset by higher physical sales volumes and margins.  The decrease in CRES capacity revenues is partially offset in other expense items below.
 
·
Transmission Revenues increased $16 million primarily due to increased transmission revenues from customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers partially offsets lost revenues included in Retail Margins above.

 
118
 
Expenses and Other and Income Tax Expense changed between years as follows:

 
·
Other Operation and Maintenance expenses increased $22 million primarily due to the following:
   
·
A $45 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase was offset by a corresponding increase in Retail Margins above.
   
·
A $35 million increase due to the first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO’s February 2012 rejection of the Ohio modified stipulation.
   
These increases were partially offset by:
   
·
A $20 million decrease due to the deferral of capacity-related costs as a result of the PUCO's July 2012 approval of the capacity deferral mechanism.
   
·
A $9 million decrease in recoverable PJM expenses.
   
·
An $8 million decrease primarily due to the 2012 reversal of storm damage deferrals as a result of the PUCO’s February 2012 rejection of the Ohio modified stipulation.
   
·
A $7 million decrease due to updated gridSMART rider allocation ratios between capital carrying charges and operations expense beginning in January 2013. This decrease was partially offset by a corresponding increase in Depreciation and Amortization.
   
·
A $6 million decrease in advertising expenses.
 
·
Asset Impairments and Other Related Charges increased $154 million due to the second quarter 2013 impairment of Muskingum River Plant, Unit 5.
 
·
Depreciation and Amortization expenses decreased $76 million primarily due to the following:
   
·
A $53 million decrease as a result of depreciation ceasing on certain generating plants that were impaired in November 2012.
   
·
A $35 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.
 
·
Interest Expense decreased $10 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
 
·
Income Tax Expense decreased $50 million primarily due to a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 220 for a discussion of accounting pronouncements.

 
119
 

 
OHIO POWER COMPANY AND SUBSIDIARY
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
For the Three and Six Months Ended June 30, 2013 and 2012
 
(in thousands)
 
(Unaudited)
   
       
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
 
REVENUES
                      
 
Electric Generation, Transmission and Distribution
  
$
 817,493 
  
$
 929,487 
  
$
 1,751,174 
  
$
 1,970,318 
 
Sales to AEP Affiliates
    
 274,390 
    
 172,561 
    
 560,032 
    
 354,318 
 
Other Revenues – Affiliated
    
 7,583 
    
 7,979 
    
 15,423 
    
 17,090 
 
Other Revenues – Nonaffiliated
    
 3,528 
    
 3,723 
    
 10,155 
    
 9,247 
 
TOTAL REVENUES
    
 1,102,994 
    
 1,113,750 
    
 2,336,784 
    
 2,350,973 
                           
 
EXPENSES
                        
 
Fuel and Other Consumables Used for Electric Generation
    
 352,368 
    
 298,294 
    
 761,952 
    
 668,287 
 
Purchased Electricity for Resale
    
 37,158 
    
 52,104 
    
 80,343 
    
 110,238 
 
Purchased Electricity from AEP Affiliates
    
 73,290 
    
 81,818 
    
 153,671 
    
 170,501 
 
Other Operation
    
 137,265 
    
 162,086 
    
 321,452 
    
 292,428 
 
Maintenance
    
 72,997 
    
 74,015 
    
 147,292 
    
 154,619 
 
Asset Impairments and Other Related Charges
    
 154,304 
    
 - 
    
 154,304 
    
 - 
 
Depreciation and Amortization
    
 102,346 
    
 137,009 
    
 194,670 
    
 271,439 
 
Taxes Other Than Income Taxes
    
 100,194 
    
 98,420 
    
 205,215 
    
 203,838 
 
TOTAL EXPENSES
    
 1,029,922 
    
 903,746 
    
 2,018,899 
    
 1,871,350 
                           
 
OPERATING INCOME
    
 73,072 
    
 210,004 
    
 317,885 
    
 479,623 
                           
 
Other Income (Expense):
                        
 
Interest Income
    
 2,326 
    
 345 
    
 2,689 
    
 1,443 
 
Carrying Costs Income
    
 3,757 
    
 4,511 
    
 7,020 
    
 7,269 
 
Allowance for Equity Funds Used During Construction
    
 521 
    
 915 
    
 1,825 
    
 2,038 
 
Interest Expense
    
 (47,244)
    
 (53,147)
    
 (97,417)
    
 (107,408)
                           
 
INCOME BEFORE INCOME TAX EXPENSE
    
 32,432 
    
 162,628 
    
 232,002 
    
 382,965 
                           
 
Income Tax Expense
    
 11,376 
    
 61,205 
    
 81,172 
    
 130,712 
                           
 
NET INCOME
  
$
 21,056 
  
$
 101,423 
  
$
 150,830 
  
$
 252,253 
                           
 
The common stock of OPCo is wholly-owned by AEP.
                        
                             
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
120
 


OHIO POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
    
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
Net Income
  
$
 21,056 
  
$
 101,423 
  
$
 150,830 
  
$
 252,253 
                           
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                        
Cash Flow Hedges, Net of Tax of $293 and $91 for the Three Months Ended
                        
 
June 30, 2013 and 2012, Respectively, and $281 and $846 for the Six
                        
 
Months Ended June 30, 2013 and 2012, Respectively
    
 (545)
    
 170 
    
 521 
    
 (1,571)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,760
                        
 
and $1,745 for the Three Months Ended June 30, 2013 and 2012,
                        
 
Respectively, and $3,520 and $3,490 for the Six Months Ended
                        
 
June 30, 2013 and 2012, Respectively
    
 3,270 
    
 3,240 
    
 6,539 
    
 6,481 
                           
TOTAL OTHER COMPREHENSIVE INCOME
    
 2,725 
    
 3,410 
    
 7,060 
    
 4,910 
                           
TOTAL COMPREHENSIVE INCOME
  
$
 23,781 
  
$
 104,833 
  
$
 157,890 
  
$
 257,163 
                           
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
121
 


OHIO POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
           
                     
Accumulated
    
                     
Other
    
   
Common
  
Paid-in
  
Retained
  
Comprehensive
    
         
Stock
  
Capital
  
Earnings
  
Income (Loss)
  
Total
TOTAL COMMON SHAREHOLDER'S
                              
   
EQUITY – DECEMBER 31, 2011
  
$
 321,201 
  
$
 1,744,099 
  
$
 2,582,600 
  
$
 (197,722)
  
$
 4,450,178 
                               
Common Stock Dividends
                
 (150,000)
          
 (150,000)
Net Income
                
 252,253 
          
 252,253 
Other Comprehensive Income
                      
 4,910 
    
 4,910 
TOTAL COMMON SHAREHOLDER'S
                              
   
EQUITY –  JUNE 30, 2012
  
$
 321,201 
  
$
 1,744,099 
  
$
 2,684,853 
  
$
 (192,812)
  
$
 4,557,341 
                               
TOTAL COMMON SHAREHOLDER'S
                              
   
EQUITY – DECEMBER 31, 2012
  
$
 321,201 
  
$
 1,744,099 
  
$
 2,626,134 
  
$
 (165,725)
  
$
 4,525,709 
                               
Common Stock Dividends
                
 (175,000)
          
 (175,000)
Net Income
                
 150,830 
          
 150,830 
Other Comprehensive Income
                      
 7,060 
    
 7,060 
TOTAL COMMON SHAREHOLDER'S
                              
   
EQUITY –  JUNE 30, 2013
  
$
 321,201 
  
$
 1,744,099 
  
$
 2,601,964 
  
$
 (158,665)
  
$
 4,508,599 
                               
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
122
 


 
OHIO POWER COMPANY AND SUBSIDIARY
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
ASSETS
 
June 30, 2013 and December 31, 2012
 
(in thousands)
 
(Unaudited)
   
         
June 30,
  
December 31,
     
2013 
  
2012 
 
CURRENT ASSETS
            
 
Cash and Cash Equivalents
  
$
 2,545 
  
$
 3,640 
 
Advances to Affiliates
    
 10,321 
    
 116,422 
 
Accounts Receivable:
            
   
Customers
    
 115,913 
    
 135,954 
   
Affiliated Companies
    
 158,313 
    
 176,590 
   
Accrued Unbilled Revenues
    
 11,674 
    
 57,887 
   
Miscellaneous
    
 3,887 
    
 9,327 
   
Allowance for Uncollectible Accounts
    
 (7,418)
    
 (129)
     
Total Accounts Receivable
    
 282,369 
    
 379,629 
 
Fuel
    
 312,293 
    
 328,840 
 
Materials and Supplies
    
 186,662 
    
 186,269 
 
Risk Management Assets
    
 41,145 
    
 44,313 
 
Accrued Tax Benefits
    
 43,706 
    
 17,785 
 
Prepayments and Other Current Assets
    
 32,684 
    
 26,807 
 
TOTAL CURRENT ASSETS
    
 911,725 
    
 1,103,705 
               
 
PROPERTY, PLANT AND EQUIPMENT
            
 
Electric:
            
   
Generation
    
 8,363,747 
    
 8,673,296 
   
Transmission
    
 2,011,693 
    
 2,013,737 
   
Distribution
    
 3,773,461 
    
 3,722,745 
 
Other Property, Plant and Equipment
    
 584,611 
    
 571,154 
 
Construction Work in Progress
    
 409,751 
    
 354,497 
 
Total Property, Plant and Equipment
    
 15,143,263 
    
 15,335,429 
 
Accumulated Depreciation and Amortization
    
 5,154,691 
    
 5,242,805 
 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    
 9,988,572 
    
 10,092,624 
               
 
OTHER NONCURRENT ASSETS
            
 
Regulatory Assets
    
 1,527,609 
    
 1,420,966 
 
Long-term Risk Management Assets
    
 33,381 
    
 48,288 
 
Deferred Charges and Other Noncurrent Assets
    
 193,947 
    
 320,026 
 
TOTAL OTHER NONCURRENT ASSETS
    
 1,754,937 
    
 1,789,280 
               
 
TOTAL ASSETS
  
$
 12,655,234 
  
$
 12,985,609 
               
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.
 
 
123
 
                   
 
OHIO POWER COMPANY AND SUBSIDIARY
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
June 30, 2013 and December 31, 2012
 
(Unaudited)
   
         
June 30,
  
December 31,
     
2013 
  
2012 
       
(in thousands)
 
CURRENT LIABILITIES
            
 
Advances from Affiliates
  
$
 292,051 
  
$
 - 
 
Accounts Payable:
            
   
General
    
 228,348 
    
 276,220 
   
Affiliated Companies
    
 112,737 
    
 153,222 
 
Long-term Debt Due Within One Year – Nonaffiliated
    
 664,450 
    
 856,000 
 
Risk Management Liabilities
    
 19,769 
    
 24,155 
 
Accrued Taxes
    
 324,412 
    
 467,309 
 
Accrued Interest
    
 52,499 
    
 63,560 
 
Other Current Liabilities
    
 231,272 
    
 263,638 
 
TOTAL CURRENT LIABILITIES
    
 1,925,538 
    
 2,104,104 
               
 
NONCURRENT LIABILITIES
            
 
Long-term Debt – Nonaffiliated
    
 2,440,344 
    
 2,804,440 
 
Long-term Debt – Affiliated
    
 400,000 
    
 200,000 
 
Long-term Risk Management Liabilities
    
 19,803 
    
 25,965 
 
Deferred Income Taxes
    
 2,412,119 
    
 2,345,850 
 
Regulatory Liabilities and Deferred Investment Tax Credits
    
 444,931 
    
 451,071 
 
Deferred Credits and Other Noncurrent Liabilities
    
 503,900 
    
 528,470 
 
TOTAL NONCURRENT LIABILITIES
    
 6,221,097 
    
 6,355,796 
               
 
TOTAL LIABILITIES
    
 8,146,635 
    
 8,459,900 
                   
 
Rate Matters (Note 3)
            
 
Commitments and Contingencies (Note 4)
            
               
 
COMMON SHAREHOLDER’S EQUITY
            
 
Common Stock – No Par Value:
            
   
Authorized – 40,000,000 Shares
            
   
Outstanding – 27,952,473 Shares
    
 321,201 
    
 321,201 
 
Paid-in Capital
    
 1,744,099 
    
 1,744,099 
 
Retained Earnings
    
 2,601,964 
    
 2,626,134 
 
Accumulated Other Comprehensive Income (Loss)
    
 (158,665)
    
 (165,725)
 
TOTAL COMMON SHAREHOLDER’S EQUITY
    
 4,508,599 
    
 4,525,709 
               
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
  
$
 12,655,234 
  
$
 12,985,609 
               
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
124
 


OHIO POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
 
         
Six Months Ended June 30,
   
2013 
  
2012 
OPERATING ACTIVITIES
            
Net Income
  
$
 150,830 
  
$
 252,253 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
            
   
Depreciation and Amortization
    
 194,670 
    
 271,439 
   
Deferred Income Taxes
    
 55,839 
    
 82,961 
   
Asset Impairments and Other Related Charges
    
 154,304 
    
 - 
   
Carrying Costs Income
    
 (7,020)
    
 (7,269)
   
Allowance for Equity Funds Used During Construction
    
 (1,825)
    
 (2,038)
   
Mark-to-Market of Risk Management Contracts
    
 9,448 
    
 (8,328)
   
Property Taxes
    
 111,392 
    
 109,892 
   
Fuel Over/Under-Recovery, Net
    
 15,267 
    
 (19,433)
   
Deferral of Ohio Capacity Costs, Net
    
 (102,240)
    
 - 
   
Change in Other Noncurrent Assets
    
 (16,273)
    
 (20,063)
   
Change in Other Noncurrent Liabilities
    
 2,421 
    
 416 
   
Changes in Certain Components of Working Capital:
            
     
Accounts Receivable, Net
    
 100,747 
    
 64,404 
     
Fuel, Materials and Supplies
    
 9,714 
    
 (70,666)
     
Accounts Payable
    
 (66,947)
    
 (134,823)
     
Accrued Taxes, Net
    
 (168,818)
    
 (115,596)
     
Other Current Assets
    
 5,391 
    
 7,982 
     
Other Current Liabilities
    
 (25,859)
    
 (13,884)
Net Cash Flows from Operating Activities
    
 421,041 
    
 397,247 
             
INVESTING ACTIVITIES
            
Construction Expenditures
    
 (296,888)
    
 (246,657)
Change in Advances to Affiliates, Net
    
 106,101 
    
 186,787 
Proceeds from Sales of Assets
    
 10,875 
    
 5,475 
Other Investing Activities
    
 1,085 
    
 6,705 
Net Cash Flows Used for Investing Activities
    
 (178,827)
    
 (47,690)
             
FINANCING ACTIVITIES
            
Issuance of Long-term Debt – Nonaffiliated
    
 49,562 
    
 - 
Issuance of Long-term Debt – Affiliated
    
 200,000 
    
 - 
Change in Advances from Affiliates, Net
    
 292,051 
    
 - 
Retirement of Long-term Debt – Nonaffiliated
    
 (606,000)
    
 (194,500)
Principal Payments for Capital Lease Obligations
    
 (4,747)
    
 (4,920)
Dividends Paid on Common Stock
    
 (175,000)
    
 (150,000)
Other Financing Activities
    
 825 
    
 134 
Net Cash Flows Used for Financing Activities
    
 (243,309)
    
 (349,286)
             
Net Increase (Decrease) in Cash and Cash Equivalents
    
 (1,095)
    
 271 
Cash and Cash Equivalents at Beginning of Period
    
 3,640 
    
 2,095 
Cash and Cash Equivalents at End of Period
  
$
 2,545 
  
$
 2,366 
             
SUPPLEMENTARY INFORMATION
            
Cash Paid for Interest, Net of Capitalized Amounts
  
$
 105,876 
  
$
 107,216 
Net Cash Paid (Received) for Income Taxes
    
 48,841 
    
 15,019 
Noncash Acquisitions Under Capital Leases
    
 3,335 
    
 4,239 
Government Grants Included in Accounts Receivable as of June 30,
    
 - 
    
 1,094 
Construction Expenditures Included in Current Liabilities as of June 30,
    
 56,618 
    
 41,873 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
125
 

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

The condensed notes to OPCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to OPCo.

 
Page
 
Number
   
Significant Accounting Matters
   154
Comprehensive Income
   154
Rate Matters
   168
Commitments, Guarantees and Contingencies
   178
Disposition and Impairment
   182
Benefit Plans
   183
Business Segments
   185
Derivatives and Hedging
   186
Fair Value Measurements
   199
Income Taxes
   211
Financing Activities
   212
Variable Interest Entities
   216
Sustainable Cost Reductions
   219

 
126
 

 
PUBLIC SERVICE COMPANY OF OKLAHOMA


 
127
 

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

EXECUTIVE OVERVIEW

Regulatory Activity

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES) Unit 4 in 2016 and additional environmental controls on NES Unit 3 to continue operations through 2026.  The plan requested approval for (a) an estimated $210 million of new environmental investment, excluding AFUDC and overheads of $46 million, that will be incurred prior to 2016 at NES Unit 3, (b) accelerated recovery through 2026 of the net book value of NES Units 3 and 4 (combined net book value of the two units is $231 million as of June 30, 2013), (c) an estimated $83 million of new investment incurred through 2016 at various gas units and (d) a new 15-year purchase power agreement with a nonaffiliated entity, effective in 2016, with cost recovery through a rider, including an annual earnings component of $3 million.  Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery in a future rate proceeding.

In January 2013, several parties filed testimony with various recommendations.  In March 2013, the OCC granted a stay in this proceeding.  In July 2013, the OCC staff filed a motion to lift the stay and dismiss PSO’s environmental compliance plan case without prejudice.  A hearing on the motion will be held in August 2013.  If this case is dismissed, 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.  See “Oklahoma Environmental Compliance Plan” section of Note 3.

Litigation and Environmental Issues

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 153.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 220 for additional discussion of relevant factors.
 
128
 

RESULTS OF OPERATIONS
                      
                           
KWh Sales/Degree Days
                      
                           
Summary of KWh Energy Sales
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
 
2013 
  
2012 
  
2013 
  
2012 
     
(in millions of KWhs)
Retail:
                      
 
Residential
  
 1,370 
    
 1,542 
    
 2,806 
    
 2,879 
 
Commercial
  
 1,275 
    
 1,373 
    
 2,354 
    
 2,474 
 
Industrial
  
 1,291 
    
 1,298 
    
 2,485 
    
 2,491 
 
Miscellaneous
  
 321 
    
 341 
    
 598 
    
 641 
Total Retail (a)
  
 4,257 
    
 4,554 
    
 8,243 
    
 8,485 
                       
Wholesale
  
 267 
    
 394 
    
 522 
    
 939 
                       
Total KWhs
  
 4,524 
    
 4,948 
    
 8,765 
    
 9,424 
                           
(a)
Represents energy delivered to distribution customers.

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

 
Summary of Heating and Cooling Degree Days
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
     
(in degree days)
 
Actual - Heating (a)
  
 119 
    
 - 
    
 1,208 
    
 676 
 
Normal - Heating (b)
  
 37 
    
 41 
    
 1,082 
    
 1,107 
                           
 
Actual - Cooling (c)
  
 644 
    
 871 
    
 649 
    
 935 
 
Normal - Cooling (b)
  
 649 
    
 635 
    
 664 
    
 648 
                           
 
(a)
Western Region heating degree days are calculated on a 55 degree temperature base.
 
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
 
(c)
Western Region cooling degree days are calculated on a 65 degree temperature base.

 
129
 


Second Quarter of 2013 Compared to Second Quarter of 2012
                   
 
Reconciliation of Second Quarter of 2012 to Second Quarter of 2013
 
Net Income
 
(in millions)
                   
 
Second Quarter of 2012
        
$
 35 
                   
 
Changes in Gross Margin:
            
 
Retail Margins (a)
          
 (7)
 
Transmission Revenues
          
 2 
 
Other Revenues
          
 1 
 
Total Change in Gross Margin
          
 (4)
               
 
Changes in Expenses and Other:
            
 
Other Operation and Maintenance
          
 (5)
 
Taxes Other Than Income Taxes
          
 (1)
 
Total Change in Expenses and Other
          
 (6)
                   
 
Income Tax Expense
          
 3 
                   
 
Second Quarter of 2013
        
$
 28 
                   
 
(a)
Includes firm wholesale sales to municipals and cooperatives.

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

 
·
Retail Margins decreased $7 million primarily due to the following:
   
·
A $7 million decrease in weather-related usage primarily due to a 26% decrease in cooling degree days.
   
·
A $2 million decrease primarily due to lower weather-normalized retail sales.
   
These decreases were partially offset by:
   
·
A $3 million increase primarily due to revenue increases from rate riders.  This increase in retail margins has corresponding increases to riders/trackers recognized in other expense items below.

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

 
·
Other Operation and Maintenance expenses increased $5 million primarily due to increased SPP transmission services.
 
·
Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income.

 
130
 


Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
                       
 
Reconciliation of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2013
 
Net Income
 
(in millions)
                       
   
Six Months Ended June 30, 2012
        
$
 48 
  
                       
   
Changes in Gross Margin:
              
   
Retail Margins (a)
          
 (6)
  
   
Transmission Revenues
          
 3 
  
   
Other Revenues
          
 (1)
  
   
Total Change in Gross Margin
          
 (4)
  
                   
   
Changes in Expenses and Other:
              
   
Other Operation and Maintenance
          
 (6)
  
   
Depreciation and Amortization
          
 (1)
  
   
Interest Expense
          
 2 
  
   
Total Change in Expenses and Other
          
 (5)
  
                       
   
Income Tax Expense
          
 3 
  
                       
   
Six Months Ended June 30, 2013
        
$
 42 
  
                       
   
(a)
Includes firm wholesale sales to municipals and cooperatives.

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

 
·
Retail Margins decreased $6 million primarily due to the following:
   
·
A $6 million decrease primarily due to lower weather-normalized retail sales.
   
·
A $4 million net decrease in weather-related usage primarily due to a 31% decrease in cooling degree days, partially offset by an increase in heating degree days.
   
These decreases were partially offset by:
   
·
A $6 million increase primarily due to revenue increases from rate riders.  This increase in retail margins has corresponding increases to riders/trackers recognized in other expense items below.
 
·
Transmission Revenues increased $3 million primarily due to rate increases for customers in the SPP region.

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

 
·
Other Operation and Maintenance expenses increased $6 million primarily due to the following:
   
·
A $9 million increase in transmission expenses primarily due to increased SPP transmission services.
   
This increase was partially offset by:
   
·
A $2 million decrease in administrative and general expenses.
 
·
Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 220 for a discussion of accounting pronouncements.

 
131
 

 
PUBLIC SERVICE COMPANY OF OKLAHOMA
 
CONDENSED STATEMENTS OF INCOME
 
For the Three and Six Months Ended June 30, 2013 and 2012
 
(in thousands)
 
(Unaudited)
                           
       
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
 
REVENUES
                      
 
Electric Generation, Transmission and Distribution
  
$
 317,302 
  
$
 311,310 
  
$
 577,205 
  
$
 603,832 
 
Sales to AEP Affiliates
    
 5,693 
    
 5,407 
    
 7,527 
    
 12,512 
 
Other Revenues
    
 1,692 
    
 594 
    
 2,244 
    
 1,498 
 
TOTAL REVENUES
    
 324,687 
    
 317,311 
    
 586,976 
    
 617,842 
                             
 
EXPENSES
                        
 
Fuel and Other Consumables Used for Electric Generation
    
 86,241 
    
 91,126 
    
 129,551 
    
 216,551 
 
Purchased Electricity for Resale
    
 58,835 
    
 44,822 
    
 123,490 
    
 70,264 
 
Purchased Electricity from AEP Affiliates
    
 6,823 
    
 4,260 
    
 17,039 
    
 10,458 
 
Other Operation
    
 53,659 
    
 48,880 
    
 101,466 
    
 95,859 
 
Maintenance
    
 24,753 
    
 24,853 
    
 53,325 
    
 53,178 
 
Depreciation and Amortization
    
 24,078 
    
 23,390 
    
 48,258 
    
 46,923 
 
Taxes Other Than Income Taxes
    
 11,827 
    
 10,681 
    
 21,824 
    
 21,820 
 
TOTAL EXPENSES
    
 266,216 
    
 248,012 
    
 494,953 
    
 515,053 
                           
 
OPERATING INCOME
    
 58,471 
    
 69,299 
    
 92,023 
    
 102,789 
                           
 
Other Income (Expense):
                        
 
Interest Income
    
 193 
    
 97 
    
 1,121 
    
 1,032 
 
Carrying Costs Income
    
 110 
    
 529 
    
 317 
    
 1,142 
 
Allowance for Equity Funds Used During Construction
    
 844 
    
 468 
    
 1,824 
    
 890 
 
Interest Expense
    
 (13,259)
    
 (13,766)
    
 (26,599)
    
 (28,477)
                           
 
INCOME BEFORE INCOME TAX EXPENSE
    
 46,359 
    
 56,627 
    
 68,686 
    
 77,376 
                           
 
Income Tax Expense
    
 17,927 
    
 21,416 
    
 26,561 
    
 29,517 
                           
 
NET INCOME
  
$
 28,432 
  
$
 35,211 
  
$
 42,125 
  
$
 47,859 
                           
 
The common stock of PSO is wholly-owned by AEP.
                        
                           
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
132
 


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
Net Income
  
$
 28,432 
  
$
 35,211 
  
$
 42,125 
  
$
 47,859 
                           
OTHER COMPREHENSIVE LOSS, NET OF TAXES
                        
Cash Flow Hedges, Net of Tax of $137 and $193 for the Three Months Ended
                        
 
June 30, 2013 and 2012, Respectively, and $227 and $222 for the Six
                        
 
Months Ended June 30, 2013 and 2012, Respectively
    
 (254)
    
 (359)
    
 (421)
    
 (412)
                           
TOTAL COMPREHENSIVE INCOME
  
$
 28,178 
  
$
 34,852 
  
$
 41,704 
  
$
 47,447 
                           
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
133
 


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
 
                     
Accumulated
    
                     
Other
    
   
Common
  
Paid-in
  
Retained
  
Comprehensive
    
         
Stock
  
Capital
  
Earnings
  
Income (Loss)
  
Total
TOTAL COMMON SHAREHOLDER'S
                              
 
EQUITY – DECEMBER 31, 2011
  
$
 157,230 
  
$
 364,037 
  
$
 364,389 
  
$
 7,149 
  
$
 892,805 
                               
Common Stock Dividends
                
 (30,000)
          
 (30,000)
Net Income
                
 47,859 
          
 47,859 
Other Comprehensive Loss
                      
 (412)
    
 (412)
TOTAL COMMON SHAREHOLDER'S
                              
 
EQUITY – JUNE 30, 2012
  
$
 157,230 
  
$
 364,037 
  
$
 382,248 
  
$
 6,737 
  
$
 910,252 
                               
TOTAL COMMON SHAREHOLDER'S
                              
 
EQUITY – DECEMBER 31, 2012
  
$
 157,230 
  
$
 364,037 
  
$
 388,530 
  
$
 6,481 
  
$
 916,278 
                               
Common Stock Dividends
                
 (27,500)
          
 (27,500)
Net Income
                
 42,125 
          
 42,125 
Other Comprehensive Loss
                      
 (421)
    
 (421)
TOTAL COMMON SHAREHOLDER'S
                              
 
EQUITY – JUNE 30, 2013
  
$
 157,230 
  
$
 364,037 
  
$
 403,155 
  
$
 6,060 
  
$
 930,482 
                               
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
134
 


 
PUBLIC SERVICE COMPANY OF OKLAHOMA
 
CONDENSED BALANCE SHEETS
 
ASSETS
 
June 30, 2013 and December 31, 2012
 
(in thousands)
 
(Unaudited)
   
         
June 30,
  
December 31,
     
2013 
  
2012 
 
CURRENT ASSETS
            
 
Cash and Cash Equivalents
  
$
 1,042 
  
$
 1,367 
 
Advances to Affiliates
    
 - 
    
 10,558 
 
Accounts Receivable:
            
   
Customers
    
 42,422 
    
 31,047 
   
Affiliated Companies
    
 21,844 
    
 24,751 
   
Miscellaneous
    
 2,336 
    
 6,216 
   
Allowance for Uncollectible Accounts
    
 (713)
    
 (872)
     
Total Accounts Receivable
    
 65,889 
    
 61,142 
 
Fuel
    
 22,459 
    
 22,085 
 
Materials and Supplies
    
 52,908 
    
 52,183 
 
Risk Management Assets
    
 484 
    
 509 
 
Deferred Income Tax Benefits
    
 2,459 
    
 7,183 
 
Accrued Tax Benefits
    
 21,358 
    
 11,812 
 
Regulatory Asset for Under-Recovered Fuel Costs
    
 9,986 
    
 - 
 
Prepayments and Other Current Assets
    
 4,880 
    
 7,633 
 
TOTAL CURRENT ASSETS
    
 181,465 
    
 174,472 
               
 
PROPERTY, PLANT AND EQUIPMENT
            
 
Electric:
            
   
Generation
    
 1,374,411 
    
 1,346,530 
   
Transmission
    
 723,331 
    
 706,917 
   
Distribution
    
 1,909,976 
    
 1,859,557 
 
Other Property, Plant and Equipment
    
 215,260 
    
 210,549 
 
Construction Work in Progress
    
 101,119 
    
 95,170 
 
Total Property, Plant and Equipment
    
 4,324,097 
    
 4,218,723 
 
Accumulated Depreciation and Amortization
    
 1,309,699 
    
 1,278,941 
 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    
 3,014,398 
    
 2,939,782 
               
 
OTHER NONCURRENT ASSETS
            
 
Regulatory Assets
    
 181,392 
    
 202,328 
 
Long-term Risk Management Assets
    
 - 
    
 31 
 
Deferred Charges and Other Noncurrent Assets
    
 27,927 
    
 8,560 
 
TOTAL OTHER NONCURRENT ASSETS
    
 209,319 
    
 210,919 
               
 
TOTAL ASSETS
  
$
 3,405,182 
  
$
 3,325,173 
               
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.
 
 
135
 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
 
CONDENSED BALANCE SHEETS
 
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
June 30, 2013 and December 31, 2012
 
(Unaudited)
               
         
June 30,
  
December 31,
     
2013 
  
2012 
       
(in thousands)
 
CURRENT LIABILITIES
            
 
Advances from Affiliates
  
$
 25,276 
  
$
 - 
 
Accounts Payable:
            
   
General
    
 96,206 
    
 87,050 
   
Affiliated Companies
    
 49,320 
    
 36,189 
 
Long-term Debt Due Within One Year – Nonaffiliated
    
 34,108 
    
 764 
 
Risk Management Liabilities
    
 2,111 
    
 5,848 
 
Customer Deposits
    
 46,223 
    
 46,533 
 
Accrued Taxes
    
 42,173 
    
 28,024 
 
Accrued Interest
    
 12,318 
    
 12,654 
 
Regulatory Liability for Over-Recovered Fuel Costs
    
 - 
    
 7,945 
 
Other Current Liabilities
    
 50,139 
    
 50,684 
 
TOTAL CURRENT LIABILITIES
    
 357,874 
    
 275,691 
               
 
NONCURRENT LIABILITIES
            
 
Long-term Debt – Nonaffiliated
    
 915,733 
    
 949,107 
 
Long-term Risk Management Liabilities
    
 2 
    
 31 
 
Deferred Income Taxes
    
 798,812 
    
 740,676 
 
Regulatory Liabilities and Deferred Investment Tax Credits
    
 329,359 
    
 344,817 
 
Employee Benefits and Pension Obligations
    
 34,853 
    
 34,906 
 
Deferred Credits and Other Noncurrent Liabilities
    
 38,067 
    
 63,667 
 
TOTAL NONCURRENT LIABILITIES
    
 2,116,826 
    
 2,133,204 
               
 
TOTAL LIABILITIES
    
 2,474,700 
    
 2,408,895 
               
               
 
Rate Matters (Note 3)
            
 
Commitments and Contingencies (Note 4)
            
               
 
COMMON SHAREHOLDER’S EQUITY
            
 
Common Stock – Par Value – $15 Per Share:
            
   
Authorized – 11,000,000 Shares
            
   
Issued – 10,482,000 Shares
            
   
Outstanding – 9,013,000 Shares
    
 157,230 
    
 157,230 
 
Paid-in Capital
    
 364,037 
    
 364,037 
 
Retained Earnings
    
 403,155 
    
 388,530 
 
Accumulated Other Comprehensive Income (Loss)
    
 6,060 
    
 6,481 
 
TOTAL COMMON SHAREHOLDER’S EQUITY
    
 930,482 
    
 916,278 
               
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
  
$
 3,405,182 
  
$
 3,325,173 
               
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
136
 


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
 
         
Six Months Ended June 30,
   
2013 
  
2012 
OPERATING ACTIVITIES
            
Net Income
  
$
 42,125 
  
$
 47,859 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating
            
 
Activities:
            
   
Depreciation and Amortization
    
 48,258 
    
 46,923 
   
Deferred Income Taxes
    
 27,562 
    
 15,275 
   
Carrying Costs Income
    
 (317)
    
 (1,142)
   
Allowance for Equity Funds Used During Construction
    
 (1,824)
    
 (890)
   
Mark-to-Market of Risk Management Contracts
    
 (3,779)
    
 4,652 
   
Property Taxes
    
 (20,353)
    
 (19,347)
   
Fuel Over/Under-Recovery, Net
    
 (19,331)
    
 76,098 
   
Change in Other Noncurrent Assets
    
 10,999 
    
 1,043 
   
Change in Other Noncurrent Liabilities
    
 (10,740)
    
 (5,409)
   
Changes in Certain Components of Working Capital:
            
     
Accounts Receivable, Net
    
 (4,747)
    
 2,560 
     
Fuel, Materials and Supplies
    
 (1,099)
    
 2,481 
     
Accounts Payable
    
 21,581 
    
 (3,263)
     
Accrued Taxes, Net
    
 13,052 
    
 32,771 
     
Other Current Assets
    
 2,257 
    
 919 
     
Other Current Liabilities
    
 (7,298)
    
 (3,987)
Net Cash Flows from Operating Activities
    
 96,346 
    
 196,543 
             
INVESTING ACTIVITIES
            
Construction Expenditures
    
 (112,864)
    
 (102,354)
Change in Advances to Affiliates, Net
    
 10,558 
    
 (80,548)
Other Investing Activities
    
 9,090 
    
 413 
Net Cash Flows Used for Investing Activities
    
 (93,216)
    
 (182,489)
             
FINANCING ACTIVITIES
            
Issuance of Long-term Debt – Nonaffiliated
    
 - 
    
 2,395 
Change in Advances from Affiliates, Net
    
 25,276 
    
 - 
Retirement of Long-term Debt – Nonaffiliated
    
 (200)
    
 (32)
Principal Payments for Capital Lease Obligations
    
 (1,586)
    
 (1,704)
Dividends Paid on Common Stock
    
 (27,500)
    
 (15,000)
Other Financing Activities
    
 555 
    
 107 
Net Cash Flows Used for Financing Activities
    
 (3,455)
    
 (14,234)
             
Net Decrease in Cash and Cash Equivalents
    
 (325)
    
 (180)
Cash and Cash Equivalents at Beginning of Period
    
 1,367 
    
 1,413 
Cash and Cash Equivalents at End of Period
  
$
 1,042 
  
$
 1,233 
             
SUPPLEMENTARY INFORMATION
            
Cash Paid for Interest, Net of Capitalized Amounts
  
$
 26,155 
  
$
 26,581 
Net Cash Paid for Income Taxes
    
 6,295 
    
 5,992 
Noncash Acquisitions Under Capital Leases
    
 5,594 
    
 759 
Construction Expenditures Included in Current Liabilities as of June 30,
    
 26,812 
    
 14,881 
Cash Dividends Declared but Not Paid
    
 - 
    
 15,000 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
137
 

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

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

 
Page
 
Number
   
Significant Accounting Matters
   154
Comprehensive Income
   154
Rate Matters
   168
Commitments, Guarantees and Contingencies
   178
Benefit Plans
   183
Business Segments
   185
Derivatives and Hedging
   186
Fair Value Measurements
   199
Income Taxes
   211
Financing Activities
   212
Variable Interest Entities
   216
Sustainable Cost Reductions
   219

 
138
 

 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

 
139
 

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

EXECUTIVE OVERVIEW

Regulatory Activity

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.  As of June 30, 2013, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital cost cap, SWEPCo has capitalized approximately $1.8 billion of expenditures, including AFUDC and capitalized interest of $328 million and related transmission costs of $118 million.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the 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 SPP market.  If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.  See “Turk Plant” section of Note 3.

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million based upon an 11.25% return on common equity to be effective January 2013.  The requested base rate increase included a return on and of the Texas jurisdictional share of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs.  In September 2012, an Administrative Law Judge (ALJ) issued an order that granted the establishment of SWEPCo’s existing rates as temporary rates beginning in late January 2013, subject to true-up to the final PUCT-approved rates.

In December 2012, several intervenors filed opposing testimony and in May 2013, the ALJ issued a proposal for decision (PFD) and added clarifications to the PFD in July 2013.  The PFD, as clarified, made various recommendations including (a) an annual base rate increase of approximately $41 million based upon a return on common equity of 9.65%, (b) the disallowance of the Turk Plant capital costs in excess of the investment and committed costs as of June 2010 plus the cost to retrofit Welsh Plant, Unit 2 which, as of June 30, 2013, SWEPCo estimates could result in a write-off of approximately $74 million (in excess of the $62 million reserve previously recorded related to the Texas capital cost cap) and (c) the exclusion, until SWEPCo’s next Texas base rate case, of the Turk Plant transmission line investment that was not in service at the end of the test year.  A decision from the PUCT is expected in the third quarter of 2013.  If the PUCT does not approve full cost recovery of SWEPCo’s assets, it could reduce future net income and cash flows and impact financial condition.  See “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 on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund.  The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover all non-fuel Turk Plant costs and a full weighted-average cost of capital return on the Turk Plant portion of rate base, effective January 2013.  In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant.  If the LPSC orders refunds based upon the pending staff review of the cost of service or prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.  See “2012 Louisiana Formula Rate Filing” section of Note 3.
 
140
 

Flint Creek Plant Environmental Controls

In 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA.  The estimated cost of the project is $408 million, excluding AFUDC and company overheads.  SWEPCo’s portion of those costs is estimated at $204 million.  As of June 30, 2013, SWEPCo has incurred $24 million related to this project, including AFUDC and company overheads.  In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant.  See the “Flint Creek Plant Environmental Controls” section of Note 3.

Litigation and Environmental Issues

In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 153.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 220 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
                      
                           
KWh Sales/Degree Days
                      
                           
Summary of KWh Energy Sales
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
 
2013 
  
2012 
  
2013 
  
2012 
     
(in millions of KWhs)
Retail:
                      
 
Residential
  
 1,446 
    
 1,570 
    
 2,940 
    
 2,952 
 
Commercial
  
 1,556 
    
 1,643 
    
 2,835 
    
 2,954 
 
Industrial
  
 1,465 
    
 1,513 
    
 2,724 
    
 2,831 
 
Miscellaneous
  
 22 
    
 21 
    
 41 
    
 41 
Total Retail (a)
  
 4,489 
    
 4,747 
    
 8,540 
    
 8,778 
                       
Wholesale
  
 2,131 
    
 1,607 
    
 4,574 
    
 3,879 
                       
Total KWhs
  
 6,620 
    
 6,354 
    
 13,114 
    
 12,657 
                           
(a)
Represents energy delivered to distribution customers.

 
141
 
Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

 
Summary of Heating and Cooling Degree Days
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
     
(in degree days)
 
Actual - Heating (a)
  
 68 
    
 4 
    
 800 
    
 427 
 
Normal - Heating (b)
  
 25 
    
 27 
    
 753 
    
 773 
                           
 
Actual - Cooling (c)
  
 703 
    
 910 
    
 719 
    
 1,024 
 
Normal - Cooling (b)
  
 725 
    
 710 
    
 758 
    
 740 
                           
 
(a)
Western Region heating degree days are calculated on a 55 degree temperature base.
 
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
 
(c)
Western Region cooling degree days are calculated on a 65 degree temperature base.

 
142
 


Second Quarter of 2013 Compared to Second Quarter of 2012
                   
 
Reconciliation of Second Quarter of 2012 to Second Quarter of 2013
 
Net Income
 
(in millions)
                   
 
Second Quarter of 2012
        
$
 55 
                   
 
Changes in Gross Margin:
            
 
Retail Margins (a)
          
 6 
 
Off-system Sales
          
 1 
 
Transmission Revenues
          
 6 
 
Total Change in Gross Margin
          
 13 
               
 
Changes in Expenses and Other:
            
 
Other Operation and Maintenance
          
 (9)
 
Asset Impairments and Other Related Charges
          
 13 
 
Depreciation and Amortization
          
 (11)
 
Taxes Other Than Income Taxes
          
 (2)
 
Allowance for Equity Funds Used During Construction
          
 (13)
 
Interest Expense
          
 (12)
 
Total Change in Expenses and Other
          
 (34)
                   
 
Income Tax Expense
          
 (4)
                   
 
Second Quarter of 2013
        
$
 30 
                   
 
(a)
Includes firm wholesale sales to municipals and cooperatives.

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

 
·
Retail Margins increased $6 million primarily due to the following:
   
·
A $24 million increase primarily due to the Louisiana formula rate order related to the Turk Plant.
   
This increase was partially offset by:
   
·
A $12 million decrease due to fuel cost adjustments.
   
·
An $8 million decrease in weather-related usage primarily due to a 23% decrease in cooling degree days.
 
·
Transmission Revenues increased $6 million primarily due rate increases for customers in the SPP region.

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

 
·
Other Operation and Maintenance expenses increased $9 million primarily due to the following:
   
·
A $5 million increase in transmission expenses primarily due to increased SPP transmission services.
   
·
A $3 million increase in generation plant operation and maintenance expenses primarily due to Turk Plant operations in addition to higher planned and unplanned plant outages.
 
·
Asset Impairments and Other Related Charges decreased $13 million due to the second quarter 2012 write-off of the expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap.
 
·
Depreciation and Amortization expenses increased $11 million primarily due to the Turk Plant being placed in service in December 2012.
 
·
Taxes Other Than Income Taxes increased $2 million primarily due to higher property taxes related to the Turk Plant being placed in service in December 2012.
 
·
Allowance for Equity Funds Used During Construction decreased $13 million primarily due to completed construction of the Turk Plant in December 2012.
 
·
Interest Expense increased $12 million primarily due to a decrease in the debt component of AFUDC due to completed construction of the Turk Plant in December 2012.
 
·
Income Tax Expense increased $4 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.

 
143
 


Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
                       
 
Reconciliation of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2013
 
Net Income
 
(in millions)
                       
   
Six Months Ended June 30, 2012
        
$
 91 
  
                       
   
Changes in Gross Margin:
              
   
Retail Margins (a)
          
 26 
  
   
Off-system Sales
          
 2 
  
   
Transmission Revenues
          
 8 
  
   
Other Revenues
          
 1 
  
   
Total Change in Gross Margin
          
 37 
  
                   
   
Changes in Expenses and Other:
              
   
Other Operation and Maintenance
          
 (23)
  
   
Asset Impairments and Other Related Charges
          
 13 
  
   
Depreciation and Amortization
          
 (22)
  
   
Taxes Other Than Income Taxes
          
 (5)
  
   
Interest Income
          
 (1)
  
   
Allowance for Equity Funds Used During Construction
          
 (26)
  
   
Interest Expense
          
 (24)
  
   
Total Change in Expenses and Other
          
 (88)
  
                       
   
Income Tax Expense
          
 2 
  
                       
   
Six Months Ended June 30, 2013
        
$
 42 
  
                       
   
(a)
Includes firm wholesale sales to municipals and cooperatives.

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

 
·
Retail Margins increased $26 million primarily due to the following:
  
   
·
A $47 million increase primarily due to the Louisiana formula rate order related to the Turk Plant.
   
This increase was partially offset by:
   
·
A $10 million decrease in municipal and cooperative revenues due to formula rate adjustments.
   
·
A $6 million decrease in weather-related usage primarily due to a 30% decrease in cooling degree days.
   
·
A $5 million decrease due to fuel cost adjustments.
 
·
 Transmission Revenues increased $8 million primarily due to rate increases for customers in the SPP region.

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

 
·
Other Operation and Maintenance expenses increased $23 million primarily due to the following:
   
·
A $9 million increase in generation plant operation and maintenance expenses primarily due to Turk Plant operations in addition to higher planned and unplanned plant outages.
   
·
An $8 million increase in transmission expenses primarily due to increased SPP transmission services.
   
·
A $2 million increase in distribution maintenance expenses primarily due to storm-related expenses.
 
·
Asset Impairments and Other Related Charges decreased $13 million due to the second quarter 2012 write-off of the expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap.
 
·
Depreciation and Amortization expenses increased $22 million primarily due to the Turk Plant being placed in service in December 2012.
 
·
Taxes Other Than Income Taxes increased $5 million primarily due to higher property taxes related to the Turk Plant being placed in service in December 2012.
 
 
144
 
 
·
Allowance for Equity Funds Used During Construction decreased $26 million primarily due to completed construction of the Turk Plant in December 2012.
 
·
Interest Expense increased $24 million primarily due to a decrease in the debt component of AFUDC due to completed construction of the Turk Plant in December 2012.
 
·
Income Tax Expense decreased $2 million primarily due to a decrease in pretax book income, partially offset by other book/tax differences which are accounted for on a flow-through basis and the regulatory accounting treatment of state income taxes.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 220 for a discussion of accounting pronouncements.

 
145
 

 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
For the Three and Six Months Ended June 30, 2013 and 2012
 
(in thousands)
 
(Unaudited)
   
       
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
 
REVENUES
                      
 
Electric Generation, Transmission and Distribution
  
$
 408,852 
  
$
 383,659 
  
$
 790,129 
  
$
 723,362 
 
Sales to AEP Affiliates
    
 10,930 
    
 6,890 
    
 23,639 
    
 15,847 
 
Other Revenues
    
 391 
    
 397 
    
 722 
    
 723 
 
TOTAL REVENUES
    
 420,173 
    
 390,946 
    
 814,490 
    
 739,932 
                             
 
EXPENSES
                        
 
Fuel and Other Consumables Used for Electric Generation
    
 137,065 
    
 138,008 
    
 288,423 
    
 266,242 
 
Purchased Electricity for Resale
    
 43,008 
    
 26,574 
    
 82,768 
    
 62,041 
 
Purchased Electricity from AEP Affiliates
    
 4,925 
    
 4,589 
    
 5,942 
    
 10,844 
 
Other Operation
    
 60,795 
    
 54,067 
    
 120,243 
    
 105,660 
 
Maintenance
    
 32,280 
    
 29,757 
    
 60,071 
    
 51,019 
 
Asset Impairments and Other Related Charges
    
 - 
    
 13,000 
    
 - 
    
 13,000 
 
Depreciation and Amortization
    
 45,732 
    
 34,655 
    
 90,614 
    
 68,676 
 
Taxes Other Than Income Taxes
    
 19,336 
    
 17,320 
    
 38,758 
    
 34,106 
 
TOTAL EXPENSES
    
 343,141 
    
 317,970 
    
 686,819 
    
 611,588 
                           
 
OPERATING INCOME
    
 77,032 
    
 72,976 
    
 127,671 
    
 128,344 
                           
 
Other Income (Expense):
                        
 
Interest Income
    
 169 
    
 11 
    
 199 
    
 1,132 
 
Allowance for Equity Funds Used During Construction
    
 1,368 
    
 14,412 
    
 2,392 
    
 28,185 
 
Interest Expense
    
 (33,547)
    
 (21,710)
    
 (67,537)
    
 (43,712)
                           
 
INCOME BEFORE INCOME TAX EXPENSE AND
                        
   
EQUITY EARNINGS
    
 45,022 
    
 65,689 
    
 62,725 
    
 113,949 
                           
 
Income Tax Expense
    
 15,326 
    
 11,505 
    
 22,122 
    
 23,977 
 
Equity Earnings of Unconsolidated Subsidiary
    
 531 
    
 718 
    
 1,172 
    
 1,325 
                           
 
NET INCOME
    
 30,227 
    
 54,902 
    
 41,775 
    
 91,297 
                           
 
Net Income Attributable to Noncontrolling Interest
    
 1,056 
    
 1,061 
    
 2,146 
    
 2,144 
                           
 
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON
                        
   
SHAREHOLDER
  
$
 29,171 
  
$
 53,841 
  
$
 39,629 
  
$
 89,153 
                           
 
The common stock of SWEPCo is wholly-owned by AEP.
                        
                           
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
146
 


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
                           
     
Three Months Ended
  
Six Months Ended
     
June 30,
  
June 30,
     
2013 
  
2012 
  
2013 
  
2012 
Net Income
  
$
 30,227 
  
$
 54,902 
  
$
 41,775 
  
$
 91,297 
                           
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
                        
Cash Flow Hedges, Net of Tax of $264 and $213 for the Three Months Ended
                        
 
June 30, 2013 and 2012, Respectively, and $585 and $743 for the
                        
 
Six Months Ended June 30, 2013 and 2012, Respectively
    
 490 
    
 396 
    
 1,086 
    
 (1,379)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $34
                        
 
and $90 for the Three Months Ended June 30, 2013 and 2012,
                        
 
Respectively, and $68 and $179 for the Six Months Ended June 30,
                        
 
2013 and 2012, Respectively
    
 (64)
    
 167 
    
 (127)
    
 332 
                           
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
    
 426 
    
 563 
    
 959 
    
 (1,047)
                           
TOTAL COMPREHENSIVE INCOME
    
 30,653 
    
 55,465 
    
 42,734 
    
 90,250 
                           
Total Comprehensive Income Attributable to Noncontrolling Interest
    
 1,056 
    
 1,061 
    
 2,146 
    
 2,144 
                         
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo
                        
 
COMMON SHAREHOLDER
  
$
 29,597 
  
$
 54,404 
  
$
 40,588 
  
$
 88,106 
                           
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
147
 


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
 
   
SWEPCo Common Shareholder
            
                     
Accumulated
          
                     
Other
          
   
Common
  
Paid-in
  
Retained
  
Comprehensive
  
Noncontrolling
    
   
Stock
  
Capital
  
Earnings
  
Income (Loss)
  
Interest
  
Total
                                           
TOTAL EQUITY – DECEMBER 31, 2011
  
$
 135,660 
  
$
 674,606 
  
$
 1,029,915 
  
$
 (26,815)
  
$
 391 
  
$
 1,813,757 
                                     
Common Stock Dividends – Nonaffiliated
                            
 (2,195)
    
 (2,195)
Net Income
                
 89,153 
          
 2,144 
    
 91,297 
Other Comprehensive Loss
                      
 (1,047)
          
 (1,047)
TOTAL EQUITY – JUNE 30, 2012
  
$
 135,660 
  
$
 674,606 
  
$
 1,119,068 
  
$
 (27,862)
  
$
 340 
  
$
 1,901,812 
                                     
TOTAL EQUITY – DECEMBER 31, 2012
  
$
 135,660 
  
$
 674,606 
  
$
 1,228,806 
  
$
 (17,860)
  
$
 261 
  
$
 2,021,473 
                                     
Common Stock Dividends
                
 (62,500)
                
 (62,500)
Common Stock Dividends – Nonaffiliated
                            
 (2,040)
    
 (2,040)
Net Income
                
 39,629 
          
 2,146 
    
 41,775 
Other Comprehensive Income
                      
 959 
          
 959 
TOTAL EQUITY – JUNE 30, 2013
  
$
 135,660 
  
$
 674,606 
  
$
 1,205,935 
  
$
 (16,901)
  
$
 367 
  
$
 1,999,667 
                                     
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
148
 


 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
ASSETS
 
June 30, 2013 and December 31, 2012
 
(in thousands)
 
(Unaudited)
   
           
June 30,
  
December 31,
     
2013 
  
2012 
 
CURRENT ASSETS
            
 
Cash and Cash Equivalents
  
$
 11,840 
  
$
 2,036 
 
Advances to Affiliates
    
 14,806 
    
 153,829 
 
Accounts Receivable:
            
     
Customers
    
 42,443 
    
 39,349 
     
Affiliated Companies
    
 30,602 
    
 26,288 
     
Miscellaneous
    
 20,958 
    
 35,514 
     
Allowance for Uncollectible Accounts
    
 (2,045)
    
 (2,041)
       
Total Accounts Receivable
    
 91,958 
    
 99,110 
 
Fuel
            
     
(June 30, 2013 and December 31, 2012 Amounts Include $36,893 and
            
     
$42,084, Respectively, Related to Sabine)
    
 137,238 
    
 134,234 
 
Materials and Supplies
    
 72,660 
    
 69,212 
 
Risk Management Assets
    
 398 
    
 695 
 
Deferred Income Tax Benefits
    
 104,894 
    
 101,403 
 
Accrued Tax Benefits
    
 30,801 
    
 9,616 
 
Regulatory Asset for Under-Recovered Fuel Costs
    
 14,210 
    
 8,527 
 
Prepayments and Other Current Assets
    
 12,795 
    
 16,489 
 
TOTAL CURRENT ASSETS
    
 491,600 
    
 595,151 
               
 
PROPERTY, PLANT AND EQUIPMENT
            
 
Electric:
            
     
Generation
    
 3,919,327 
    
 3,888,230 
     
Transmission
    
 1,140,451 
    
 1,115,795 
     
Distribution
    
 1,794,684 
    
 1,758,988 
 
Other Property, Plant and Equipment
            
     
(June 30, 2013 and December 31, 2012 Amounts Include $288,776 and
            
     
$287,032, Respectively, Related to Sabine)
    
 695,944 
    
 688,254 
 
Construction Work in Progress
    
 153,715 
    
 99,783 
 
Total Property, Plant and Equipment
    
 7,704,121 
    
 7,551,050 
 
Accumulated Depreciation and Amortization
            
     
(June 30, 2013 and December 31, 2012 Amounts Include $125,834 and
            
     
$116,597, Respectively, Related to Sabine)
    
 2,353,562 
    
 2,284,258 
 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    
 5,350,559 
    
 5,266,792 
               
 
OTHER NONCURRENT ASSETS
            
 
Regulatory Assets
    
 407,408 
    
 403,278 
 
Deferred Charges and Other Noncurrent Assets
    
 100,880 
    
 76,432 
 
TOTAL OTHER NONCURRENT ASSETS
    
 508,288 
    
 479,710 
               
 
TOTAL ASSETS
  
$
 6,350,447 
  
$
 6,341,653 
               
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.
 
 
149
 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
LIABILITIES AND EQUITY
 
June 30, 2013 and December 31, 2012
 
(Unaudited)
   
           
June 30,
  
December 31,
     
2013 
  
2012 
       
(in thousands)
 
CURRENT LIABILITIES
            
 
Accounts Payable:
            
     
General
  
$
 107,438 
  
$
 126,768 
     
Affiliated Companies
    
 64,553 
    
 62,835 
 
Short-term Debt – Nonaffiliated
    
 - 
    
 2,603 
 
Long-term Debt Due Within One Year – Nonaffiliated
    
 3,250 
    
 3,250 
 
Risk Management Liabilities
    
 941 
    
 1,128 
 
Customer Deposits
    
 55,658 
    
 69,393 
 
Accrued Taxes
    
 63,796 
    
 31,532 
 
Accrued Interest
    
 43,335 
    
 43,950 
 
Obligations Under Capital Leases
    
 17,978 
    
 17,599 
 
Regulatory Liability for Over-Recovered Fuel Costs
    
 5,102 
    
 16,761 
 
Other Current Liabilities
    
 66,388 
    
 64,997 
 
TOTAL CURRENT LIABILITIES
    
 428,439 
    
 440,816 
               
 
NONCURRENT LIABILITIES
            
 
Long-term Debt – Nonaffiliated
    
 2,041,530 
    
 2,042,978 
 
Long-term Risk Management Liabilities
    
 3 
    
 - 
 
Deferred Income Taxes
    
 1,122,609 
    
 1,075,551 
 
Regulatory Liabilities and Deferred Investment Tax Credits
    
 472,434 
    
 476,471 
 
Asset Retirement Obligations
    
 86,998 
    
 78,017 
 
Employee Benefits and Pension Obligations
    
 41,795 
    
 38,240 
 
Obligations Under Capital Leases
    
 107,728 
    
 114,161 
 
Deferred Credits and Other Noncurrent Liabilities
    
 49,244 
    
 53,946 
 
TOTAL NONCURRENT LIABILITIES
    
 3,922,341 
    
 3,879,364 
               
 
TOTAL LIABILITIES
    
 4,350,780 
    
 4,320,180 
               
 
Rate Matters (Note 3)
            
 
Commitments and Contingencies (Note 4)
            
               
 
EQUITY
            
 
Common Stock – Par Value – $18 Per Share:
            
     
Authorized – 7,600,000 Shares
            
     
Outstanding – 7,536,640 Shares
    
 135,660 
    
 135,660 
 
Paid-in Capital
    
 674,606 
    
 674,606 
 
Retained Earnings
    
 1,205,935 
    
 1,228,806 
 
Accumulated Other Comprehensive Income (Loss)
    
 (16,901)
    
 (17,860)
 
TOTAL COMMON SHAREHOLDER’S EQUITY
    
 1,999,300 
    
 2,021,212 
               
 
Noncontrolling Interest
    
 367 
    
 261 
               
 
TOTAL EQUITY
    
 1,999,667 
    
 2,021,473 
               
 
TOTAL LIABILITIES AND EQUITY
  
$
 6,350,447 
  
$
 6,341,653 
               
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
150
 


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)
 
         
Six Months Ended June 30,
   
2013 
  
2012 
OPERATING ACTIVITIES
            
Net Income
  
$
 41,775 
  
$
 91,297 
Adjustments to Reconcile Net Income to Net Cash Flows from
            
 
 Operating Activities:
            
   
Depreciation and Amortization
    
 90,614 
    
 68,676 
   
Deferred Income Taxes
    
 39,624 
    
 138,594 
   
Asset Impairments and Other Related Charges
    
 - 
    
 13,000 
   
Allowance for Equity Funds Used During Construction
    
 (2,392)
    
 (28,185)
   
Mark-to-Market of Risk Management Contracts
    
 35 
    
 1,927 
   
Property Taxes
    
 (23,607)
    
 (19,790)
   
Fuel Over/Under-Recovery, Net
    
 (17,350)
    
 (4,398)
   
Change in Other Noncurrent Assets
    
 (3,639)
    
 1,678 
   
Change in Other Noncurrent Liabilities
    
 5,647 
    
 17,707 
   
Changes in Certain Components of Working Capital:
            
     
Accounts Receivable, Net
    
 6,979 
    
 (12,989)
     
Fuel, Materials and Supplies
    
 (6,452)
    
 (16,901)
     
Accounts Payable
    
 1,277 
    
 2,938 
     
Accrued Taxes, Net
    
 11,079 
    
 (40,616)
     
Other Current Assets
    
 3,541 
    
 (7,685)
     
Other Current Liabilities
    
 (12,121)
    
 (6,367)
Net Cash Flows from Operating Activities
    
 135,010 
    
 198,886 
             
INVESTING ACTIVITIES
            
Construction Expenditures
    
 (187,607)
    
 (246,957)
Change in Advances to Affiliates, Net
    
 139,023 
    
 (97,022)
Other Investing Activities
    
 342 
    
 (1,927)
Net Cash Flows Used for Investing Activities
    
 (48,242)
    
 (345,906)
             
FINANCING ACTIVITIES
            
Issuance of Long-term Debt – Nonaffiliated
    
 - 
    
 336,576 
Credit Facility Borrowings
    
 17,091 
    
 21,462 
Change in Advances from Affiliates, Net
    
 - 
    
 (132,473)
Retirement of Long-term Debt – Nonaffiliated
    
 (1,625)
    
 (20,000)
Credit Facility Repayments
    
 (19,694)
    
 (38,478)
Principal Payments for Capital Lease Obligations
    
 (8,877)
    
 (7,899)
Dividends Paid on Common Stock
    
 (62,500)
    
 - 
Dividends Paid on Common Stock – Nonaffiliated
    
 (2,040)
    
 (2,195)
Other Financing Activities
    
 681 
    
 3,843 
Net Cash Flows from (Used for) Financing Activities
    
 (76,964)
    
 160,836 
             
Net Increase in Cash and Cash Equivalents
    
 9,804 
    
 13,816 
Cash and Cash Equivalents at Beginning of Period
    
 2,036 
    
 801 
Cash and Cash Equivalents at End of Period
  
$
 11,840 
  
$
 14,617 
             
SUPPLEMENTARY INFORMATION
            
Cash Paid for Interest, Net of Capitalized Amounts
  
$
 61,663 
  
$
 32,595 
Net Cash Paid (Received) for Income Taxes
    
 1,161 
    
 (47,741)
Noncash Acquisitions Under Capital Leases
    
 2,851 
    
 12,350 
Construction Expenditures Included in Current Liabilities as of June 30,
    
 35,940 
    
 79,960 
             
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

 
151
 

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

The condensed notes to SWEPCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to SWEPCo.

 
Page
 
Number
   
Significant Accounting Matters
   154
Comprehensive Income
   154
Rate Matters
   168
Commitments, Guarantees and Contingencies
   178
Benefit Plans
   183
Business Segments
   185
Derivatives and Hedging
   186
Fair Value Measurements
   199
Income Taxes
   211
Financing Activities
   212
Variable Interest Entities
   216
Sustainable Cost Reductions
   219


 
152
 

 
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to condensed financial statements that follow are a combined presentation for the Registrant Subsidiaries.  The following list indicates the registrants to which the footnotes apply:

   
Page
   
Number
     
Significant Accounting Matters
APCo, I&M, OPCo, PSO, SWEPCo
   154
Comprehensive Income
APCo, I&M, OPCo, PSO, SWEPCo
   154
Rate Matters
APCo, I&M, OPCo, PSO, SWEPCo
   168
Commitments, Guarantees and Contingencies
APCo, I&M, OPCo, PSO, SWEPCo
   178
Disposition and Impairment
OPCo
   182
Benefit Plans
APCo, I&M, OPCo, PSO, SWEPCo
   183
Business Segments
APCo, I&M, OPCo, PSO, SWEPCo
   185
Derivatives and Hedging
APCo, I&M, OPCo, PSO, SWEPCo
   186
Fair Value Measurements
APCo, I&M, OPCo, PSO, SWEPCo
   199
Income Taxes
APCo, I&M, OPCo, PSO, SWEPCo
   211
Financing Activities
APCo, I&M, OPCo, PSO, SWEPCo
   212
Variable Interest Entities
APCo, I&M, OPCo, PSO, SWEPCo
   216
Sustainable Cost Reductions
APCo, I&M, OPCo, PSO, SWEPCo
   219

 
153
 

1.  SIGNIFICANT ACCOUNTING MATTERS

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC.  Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary.  Net income for the three and six months ended June 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2012 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2012 as filed with the SEC on February 26, 2013.

2.  COMPREHENSIVE INCOME

Presentation of Comprehensive Income

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

APCo
                      
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 
For the Three Months Ended June 30, 2013
                         
       
Cash Flow Hedges
            
             
Interest Rate and
  
Pension
      
       
Commodity
  
Foreign Currency
  
and OPEB
  
Total
       
(in thousands)
 
Balance in AOCI as of March 31, 2013
$
 361 
  
$
 2,330 
  
$
 (30,973)
  
$
 (28,282)
 
Change in Fair Value Recognized in AOCI
  
 (63)
    
 1 
    
 - 
    
 (62)
 
Amounts Reclassified from AOCI
  
 (101)
    
 252 
    
 358 
    
 509 
 
Net Current Period Other
                      
     
Comprehensive Income
  
 (164)
    
 253 
    
 358 
    
 447 
 
Balance in AOCI as of June 30, 2013
$
 197 
  
$
 2,583 
  
$
 (30,615)
  
$
 (27,835)

APCo
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 
For the Six Months Ended June 30, 2013
                         
       
Cash Flow Hedges
            
             
Interest Rate and
  
Pension
      
       
Commodity
  
Foreign Currency
  
and OPEB
  
Total
       
(in thousands)
 
Balance in AOCI as of December 31, 2012
$
 (644)
  
$
 2,077 
  
$
 (31,331)
  
$
 (29,898)
 
Change in Fair Value Recognized in AOCI
  
 731 
    
 - 
    
 - 
    
 731 
 
Amounts Reclassified from AOCI
  
 110 
    
 506 
    
 716 
    
 1,332 
 
Net Current Period Other
                      
     
Comprehensive Income
  
 841 
    
 506 
    
 716 
    
 2,063 
 
Balance in AOCI as of June 30, 2013
$
 197 
  
$
 2,583 
  
$
 (30,615)
  
$
 (27,835)

 
154
 
I&M
                      
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 
For the Three Months Ended June 30, 2013
                         
       
Cash Flow Hedges
            
             
Interest Rate and
  
Pension
      
       
Commodity
  
Foreign Currency
  
and OPEB
  
Total
       
(in thousands)
 
Balance in AOCI as of March 31, 2013
$
 236 
  
$
 (17,206)
  
$
 (8,614)
  
$
 (25,584)
 
Change in Fair Value Recognized in AOCI
  
 (40)
    
 (1)
    
 - 
    
 (41)
 
Amounts Reclassified from AOCI
  
 (49)
    
 411 
    
 175 
    
 537 
 
Net Current Period Other
                      
     
Comprehensive Income
  
 (89)
    
 410 
    
 175 
    
 496 
 
Balance in AOCI as of June 30, 2013
$
 147 
  
$
 (16,796)
  
$
 (8,439)
  
$
 (25,088)

I&M
                      
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 
For the Six Months Ended June 30, 2013
                         
       
Cash Flow Hedges
            
             
Interest Rate and
  
Pension
      
       
Commodity
  
Foreign Currency
  
and OPEB
  
Total
       
(in thousands)
 
Balance in AOCI as of December 31, 2012
$
 (446)
  
$
 (19,647)
  
$
 (8,790)
  
$
 (28,883)
 
Change in Fair Value Recognized in AOCI
  
 492 
    
 2,248 
    
 - 
    
 2,740 
 
Amounts Reclassified from AOCI
  
 101 
    
 603 
    
 351 
    
 1,055 
 
Net Current Period Other
                      
     
Comprehensive Income
  
 593 
    
 2,851 
    
 351 
    
 3,795 
 
Balance in AOCI as of June 30, 2013
$
 147 
  
$
 (16,796)
  
$
 (8,439)
  
$
 (25,088)

OPCo
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 
For the Three Months Ended June 30, 2013
                         
       
Cash Flow Hedges
            
             
Interest Rate and
  
Pension
      
       
Commodity
  
Foreign Currency
  
and OPEB
  
Total
       
(in thousands)
 
Balance in AOCI as of March 31, 2013
$
 494 
  
$
 7,755 
  
$
 (169,639)
  
$
 (161,390)
 
Change in Fair Value Recognized in AOCI
  
 (109)
    
 - 
    
 - 
    
 (109)
 
Amounts Reclassified from AOCI
  
 (96)
    
 (340)
    
 3,270 
    
 2,834 
 
Net Current Period Other
                      
     
Comprehensive Income
  
 (205)
    
 (340)
    
 3,270 
    
 2,725 
 
Balance in AOCI as of June 30, 2013
$
 289 
  
$
 7,415 
  
$
 (166,369)
  
$
 (158,665)

OPCo
                      
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 
For the Six Months Ended June 30, 2013
                         
       
Cash Flow Hedges
            
             
Interest Rate and
  
Pension
      
       
Commodity
  
Foreign Currency
  
and OPEB
  
Total
       
(in thousands)
 
Balance in AOCI as of December 31, 2012
$
 (912)
  
$
 8,095 
  
$
 (172,908)
  
$
 (165,725)
 
Change in Fair Value Recognized in AOCI
  
 993 
    
 - 
    
 - 
    
 993 
 
Amounts Reclassified from AOCI
  
 208 
    
 (680)
    
 6,539 
    
 6,067 
 
Net Current Period Other
                      
     
Comprehensive Income
  
 1,201 
    
 (680)
    
 6,539 
    
 7,060 
 
Balance in AOCI as of June 30, 2013
$
 289 
  
$
 7,415 
  
$
 (166,369)
  
$
 (158,665)

 
155
PSO
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2013
                 
     
Cash Flow Hedges
      
           
Interest Rate and
      
     
Commodity
  
Foreign Currency
  
Total
     
(in thousands)
Balance in AOCI as of March 31, 2013
$
 44 
  
$
 6,270 
  
$
 6,314 
Change in Fair Value Recognized in AOCI
  
 (61)
    
 1 
    
 (60)
Amounts Reclassified from AOCI
  
 (4)
    
 (190)
    
 (194)
Net Current Period Other
                
   
Comprehensive Income
  
 (65)
    
 (189)
    
 (254)
Balance in AOCI as of June 30, 2013
$
 (21)
  
$
 6,081 
  
$
 6,060 
 
PSO
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2013
                 
     
Cash Flow Hedges
      
           
Interest Rate and
      
     
Commodity
  
Foreign Currency
  
Total
     
(in thousands)
Balance in AOCI as of December 31, 2012
$
 21 
  
$
 6,460 
  
$
 6,481 
Change in Fair Value Recognized in AOCI
  
 (25)
    
 1 
    
 (24)
Amounts Reclassified from AOCI
  
 (17)
    
 (380)
    
 (397)
Net Current Period Other
                
   
Comprehensive Income
  
 (42)
    
 (379)
    
 (421)
Balance in AOCI as of June 30, 2013
$
 (21)
  
$
 6,081 
  
$
 6,060 

SWEPCo
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 
For the Three Months Ended June 30, 2013
                         
       
Cash Flow Hedges
            
             
Interest Rate and
  
Pension
      
       
Commodity
  
Foreign Currency
  
and OPEB
  
Total
       
(in thousands)
 
Balance in AOCI as of March 31, 2013
$
 51 
  
$
 (15,004)
  
$
 (2,374)
  
$
 (17,327)
 
Change in Fair Value Recognized in AOCI
  
 (71)
    
 - 
    
 - 
    
 (71)
 
Amounts Reclassified from AOCI
  
 (6)
    
 567 
    
 (64)
    
 497 
 
Net Current Period Other
                      
     
Comprehensive Income
  
 (77)
    
 567 
    
 (64)
    
 426 
 
Balance in AOCI as of June 30, 2013
$
 (26)
  
$
 (14,437)
  
$
 (2,438)
  
$
 (16,901)

SWEPCo
                      
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 
For the Six Months Ended June 30, 2013
                         
       
Cash Flow Hedges
            
             
Interest Rate and
  
Pension
      
       
Commodity
  
Foreign Currency
  
and OPEB
  
Total
       
(in thousands)
 
Balance in AOCI as of December 31, 2012
$
 22 
  
$
 (15,571)
  
$
 (2,311)
  
$
 (17,860)
 
Change in Fair Value Recognized in AOCI
  
 (27)
    
 - 
    
 - 
    
 (27)
 
Amounts Reclassified from AOCI
  
 (21)
    
 1,134 
    
 (127)
    
 986 
 
Net Current Period Other
                      
     
Comprehensive Income
  
 (48)
    
 1,134 
    
 (127)
    
 959 
 
Balance in AOCI as of June 30, 2013
$
 (26)
  
$
 (14,437)
  
$
 (2,438)
  
$
 (16,901)

 
156
 
Reclassifications Out of Accumulated Other Comprehensive Income

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

APCo
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Three Months Ended June 30, 2013
         
         
Amount of
         
(Gain) Loss
         
 Reclassified
         
from AOCI
 
Gains and Losses on Cash Flow Hedges
  
(in thousands)
 
Commodity:
      
     
Electric Generation, Transmission and Distribution Revenues
  
$
 2 
     
Purchased Electricity for Resale
    
 (31)
     
Other Operation Expense
    
 (13)
     
Maintenance Expense
    
 (2)
     
Property, Plant and Equipment
    
 (5)
     
Regulatory Assets (a)
    
 (108)
 
Subtotal - Commodity
    
 (157)
             
 
Interest Rate and Foreign Currency:
      
     
Interest Expense
    
 389 
 
Subtotal - Interest Rate and Foreign Currency
    
 389 
             
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 232 
 
Income Tax (Expense) Credit
    
 81 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 151 
         
 
Amortization of Pension and OPEB
      
 
Prior Service Cost (Credit)
    
 (1,283)
 
Actuarial (Gains)/Losses
    
 1,834 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 551 
 
Income Tax (Expense) Credit
    
 193 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 358 
             
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
  
$
 509 

 
157
 
APCo
      
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Six Months Ended June 30, 2013
         
         
Amount of
         
(Gain) Loss
         
 Reclassified
         
from AOCI
 
Gains and Losses on Cash Flow Hedges
  
(in thousands)
 
Commodity:
      
     
Electric Generation, Transmission and Distribution Revenues
  
$
 22 
     
Purchased Electricity for Resale
    
 26 
     
Other Operation Expense
    
 (24)
     
Maintenance Expense
    
 (18)
     
Property, Plant and Equipment
    
 (19)
     
Regulatory Assets (a)
    
 181 
 
Subtotal - Commodity
    
 168 
             
 
Interest Rate and Foreign Currency:
      
     
Interest Expense
    
 779 
 
Subtotal - Interest Rate and Foreign Currency
    
 779 
             
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 947 
 
Income Tax (Expense) Credit
    
 331 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 616 
         
 
Amortization of Pension and OPEB
      
 
Prior Service Cost (Credit)
    
 (2,565)
 
Actuarial (Gains)/Losses
    
 3,667 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 1,102 
 
Income Tax (Expense) Credit
    
 386 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 716 
             
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
  
$
 1,332 

 
158
 
I&M
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Three Months Ended June 30, 2013
         
         
Amount of
         
(Gain) Loss
         
Reclassified
         
from AOCI
 
Gains and Losses on Cash Flow Hedges
  
(in thousands)
 
Commodity:
      
     
Electric Generation, Transmission and Distribution Revenues
  
$
 32 
     
Purchased Electricity for Resale
    
 (81)
     
Other Operation Expense
    
 (8)
     
Maintenance Expense
    
 (2)
     
Property, Plant and Equipment
    
 (3)
     
Regulatory Assets (a)
    
 (12)
 
Subtotal - Commodity
    
 (74)
             
 
Interest Rate and Foreign Currency:
      
     
Interest Expense
    
 631 
 
Subtotal - Interest Rate and Foreign Currency
    
 631 
             
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 557 
 
Income Tax (Expense) Credit
    
 195 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 362 
         
 
Amortization of Pension and OPEB
      
 
Prior Service Cost (Credit)
    
 (198)
 
Actuarial (Gains)/Losses
    
 468 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 270 
 
Income Tax (Expense) Credit
    
 95 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 175 
             
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
  
$
 537 

 
159
 
I&M
      
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Six Months Ended June 30, 2013
         
         
Amount of
         
(Gain) Loss
         
Reclassified
         
from AOCI
 
Gains and Losses on Cash Flow Hedges
  
(in thousands)
 
Commodity:
      
     
Electric Generation, Transmission and Distribution Revenues
  
$
 84 
     
Purchased Electricity for Resale
    
 68 
     
Other Operation Expense
    
 (15)
     
Maintenance Expense
    
 (9)
     
Property, Plant and Equipment
    
 (10)
     
Regulatory Assets (a)
    
 38 
 
Subtotal - Commodity
    
 156 
             
 
Interest Rate and Foreign Currency:
      
     
Interest Expense
    
 927 
 
Subtotal - Interest Rate and Foreign Currency
    
 927 
             
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 1,083 
 
Income Tax (Expense) Credit
    
 379 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 704 
         
 
Amortization of Pension and OPEB
      
 
Prior Service Cost (Credit)
    
 (397)
 
Actuarial (Gains)/Losses
    
 937 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 540 
 
Income Tax (Expense) Credit
    
 189 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 351 
             
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
  
$
 1,055 

 
160
 
OPCo
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Three Months Ended June 30, 2013
         
         
Amount of
         
(Gain) Loss
         
Reclassified
         
from AOCI
 
Gains and Losses on Cash Flow Hedges
  
(in thousands)
 
Commodity:
      
     
Electric Generation, Transmission and Distribution Revenues
  
$
 81 
     
Purchased Electricity for Resale
    
 (202)
     
Other Operation Expense
    
 (19)
     
Maintenance Expense
    
 (3)
     
Property, Plant and Equipment
    
 (4)
 
Subtotal - Commodity
    
 (147)
             
 
Interest Rate and Foreign Currency:
      
     
Depreciation and Amortization Expense
    
 1 
     
Interest Expense
    
 (525)
 
Subtotal - Interest Rate and Foreign Currency
    
 (524)
             
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 (671)
 
Income Tax (Expense) Credit
    
 (235)
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 (436)
         
 
Amortization of Pension and OPEB
      
 
Prior Service Cost (Credit)
    
 (1,469)
 
Actuarial (Gains)/Losses
    
 6,499 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 5,030 
 
Income Tax (Expense) Credit
    
 1,760 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 3,270 
             
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
  
$
 2,834 

 
161
 
OPCo
      
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Six Months Ended June 30, 2013
         
         
Amount of
         
(Gain) Loss
         
Reclassified
         
from AOCI
 
Gains and Losses on Cash Flow Hedges
  
(in thousands)
 
Commodity:
      
     
Electric Generation, Transmission and Distribution Revenues
  
$
 215 
     
Purchased Electricity for Resale
    
 180 
     
Other Operation Expense
    
 (37)
     
Maintenance Expense
    
 (15)
     
Property, Plant and Equipment
    
 (23)
 
Subtotal - Commodity
    
 320 
             
 
Interest Rate and Foreign Currency:
      
     
Depreciation and Amortization Expense
    
 3 
     
Interest Expense
    
 (1,049)
 
Subtotal - Interest Rate and Foreign Currency
    
 (1,046)
             
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 (726)
 
Income Tax (Expense) Credit
    
 (254)
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 (472)
         
 
Amortization of Pension and OPEB
      
 
Prior Service Cost (Credit)
    
 (2,937)
 
Actuarial (Gains)/Losses
    
 12,996 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 10,059 
 
Income Tax (Expense) Credit
    
 3,520 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 6,539 
             
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
  
$
 6,067 

 
162
 
PSO
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Three Months Ended June 30, 2013
         
         
Amount of
         
(Gain) Loss
         
Reclassified
         
from AOCI
 
Gains and Losses on Cash Flow Hedges
  
(in thousands)
 
Commodity:
      
     
Other Operation Expense
  
$
 (6)
     
Maintenance Expense
    
 - 
     
Property, Plant and Equipment
    
 - 
 
Subtotal - Commodity
    
 (6)
             
 
Interest Rate and Foreign Currency:
      
     
Interest Expense
    
 (292)
 
Subtotal - Interest Rate and Foreign Currency
    
 (292)
             
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 (298)
 
Income Tax (Expense) Credit
    
 (104)
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
  
$
 (194)

PSO
      
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Six Months Ended June 30, 2013
         
         
Amount of
         
(Gain) Loss
         
Reclassified
         
from AOCI
 
Gains and Losses on Cash Flow Hedges
  
(in thousands)
 
Commodity:
      
     
Other Operation Expense
  
$
 (15)
     
Maintenance Expense
    
 (4)
     
Property, Plant and Equipment
    
 (7)
 
Subtotal - Commodity
    
 (26)
             
 
Interest Rate and Foreign Currency:
      
     
Interest Expense
    
 (584)
 
Subtotal - Interest Rate and Foreign Currency
    
 (584)
             
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 (610)
 
Income Tax (Expense) Credit
    
 (213)
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
  
$
 (397)

 
163
 
SWEPCo
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Three Months Ended June 30, 2013
         
         
Amount of
         
(Gain) Loss
         
Reclassified
         
from AOCI
 
Gains and Losses on Cash Flow Hedges
  
(in thousands)
 
Commodity:
      
     
Other Operation Expense
  
$
 (6)
     
Maintenance Expense
    
 (1)
     
Property, Plant and Equipment
    
 (1)
 
Subtotal - Commodity
    
 (8)
             
 
Interest Rate and Foreign Currency:
      
     
Interest Expense
    
 872 
 
Subtotal - Interest Rate and Foreign Currency
    
 872 
             
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 864 
 
Income Tax (Expense) Credit
    
 303 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 561 
         
 
Amortization of Pension and OPEB
      
 
Prior Service Cost (Credit)
    
 (447)
 
Actuarial (Gains)/Losses
    
 348 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 (99)
 
Income Tax (Expense) Credit
    
 (35)
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 (64)
             
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
  
$
 497 

 
164
 
SWEPCo
      
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Six Months Ended June 30, 2013
         
         
Amount of
         
(Gain) Loss
         
Reclassified
         
from AOCI
 
Gains and Losses on Cash Flow Hedges
  
(in thousands)
 
Commodity:
      
     
Other Operation Expense
  
$
 (16)
     
Maintenance Expense
    
 (7)
     
Property, Plant and Equipment
    
 (8)
 
Subtotal - Commodity
    
 (31)
             
 
Interest Rate and Foreign Currency:
      
     
Interest Expense
    
 1,744 
 
Subtotal - Interest Rate and Foreign Currency
    
 1,744 
             
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 1,713 
 
Income Tax (Expense) Credit
    
 600 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 1,113 
         
 
Amortization of Pension and OPEB
      
 
Prior Service Cost (Credit)
    
 (892)
 
Actuarial (Gains)/Losses
    
 696 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
    
 (196)
 
Income Tax (Expense) Credit
    
 (69)
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
    
 (127)
             
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
  
$
 986 

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

 
165
 
The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2012.  All amounts in the following tables are presented net of related income taxes.

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

 
166
 


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

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

 
167
 
3.  RATE MATTERS

As discussed in the 2012 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within the 2012 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition.  The following discusses ratemaking developments in 2013 and updates the 2012 Annual Report.

Regulatory Assets Not Yet Being Recovered

         
APCo
         
June 30,
  
December 31,
         
2013 
  
2012 
 
Noncurrent Regulatory Assets
  
(in thousands)
 
Regulatory assets not yet being recovered pending future proceedings:
            
                   
 
Regulatory Assets Currently Not Earning a Return
            
   
Storm Related Costs
  
$
 65,206 
  
$
 94,458 
   
Virginia Environmental Rate Adjustment Clause
    
 28,777 
    
 29,320 
   
Mountaineer Carbon Capture and Storage
            
     
Product Validation Facility
    
 14,155 
    
 14,155 
   
Dresden Plant Operating Costs
    
 8,760 
    
 8,758 
   
Deferred Wind Power Costs
    
 - 
    
 5,143 
   
Transmission Agreement Phase-In
    
 3,267 
    
 2,992 
   
Mountaineer Carbon Capture and Storage
            
     
Commercial Scale Facility
    
 1,287 
    
 1,287 
   
Other Regulatory Assets Not Yet Being Recovered
    
 3,652 
    
 1,447 
 
Total Regulatory Assets Not Yet Being Recovered
  
$
 125,104 
  
$
 157,560 

         
I&M
         
June 30,
  
December 31,
         
2013 
  
2012 
 
Noncurrent Regulatory Assets
  
(in thousands)
 
Regulatory assets not yet being recovered pending future proceedings:
            
                   
 
Regulatory Assets Currently Not Earning a Return
            
   
Litigation Settlement
  
$
 - 
  
$
 11,098 
   
Mountaineer Carbon Capture and Storage
            
     
Commercial Scale Facility
    
 - 
    
 1,380 
   
Under-Recovered Capacity Costs
    
 10,792 
    
 - 
   
Other Regulatory Asset Not Yet Being Recovered
    
 2,634 
    
 786 
 
Total Regulatory Assets Not Yet Being Recovered
  
$
 13,426 
  
$
 13,264 

         
OPCo
         
June 30,
  
December 31,
         
2013 
  
2012 
 
Noncurrent Regulatory Assets
  
(in thousands)
 
Regulatory assets not yet being recovered pending future proceedings:
            
                   
 
Regulatory Assets Currently Earning a Return
            
   
Economic Development Rider
  
$
 13,533 
  
$
 13,213 
 
Regulatory Assets Currently Not Earning a Return
            
   
Storm Related Costs
    
 58,512 
    
 61,828 
   
Ormet Delayed Payment Arrangement
    
 20,000 
    
 5,453 
   
Other Regulatory Assets Not Yet Being Recovered
    
 706 
    
 30 
 
Total Regulatory Assets Not Yet Being Recovered
  
$
 92,751 
  
$
 80,524 

 
168
 
         
PSO
         
June 30,
  
December 31,
         
2013 
  
2012 
 
Noncurrent Regulatory Assets
  
(in thousands)
 
Regulatory assets not yet being recovered pending future proceedings:
            
                   
 
Regulatory Assets Currently Not Earning a Return
            
   
Other Regulatory Assets Not Yet Being Recovered
  
$
 803 
  
$
 423 
 
Total Regulatory Assets Not Yet Being Recovered
  
$
 803 
  
$
 423 

         
SWEPCo
         
June 30,
  
December 31,
         
2013 
  
2012 
 
Noncurrent Regulatory Assets
  
(in thousands)
 
Regulatory assets not yet being recovered pending future proceedings:
            
                   
 
Regulatory Assets Currently Not Earning a Return
            
   
Rate Case Expenses
  
$
 7,234 
  
$
 4,517 
   
Mountaineer Carbon Capture and Storage
            
     
Commercial Scale Facility
    
 2,295 
    
 2,295 
   
Other Regulatory Assets Not Yet Being Recovered
    
 2,373 
    
 2,188 
 
Total Regulatory Assets Not Yet Being Recovered
  
$
 11,902 
  
$
 9,000 

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

OPCo Rate Matters

Ohio Electric Security Plan Filing

2009 – 2011 ESP

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

In October 2011, the PUCO issued an order in the remand proceeding.  As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011.  In February 2012, the Ohio Consumers’ Counsel and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance.  As of June 30, 2013, OPCo’s net deferred fuel balance was $484 million, excluding unrecognized equity carrying costs.  A decision from the Supreme Court of Ohio is pending.

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off in 2010 and a subsequent refund to customers during 2011.  The IEU and the Ohio Energy Group filed appeals with the Supreme Court of Ohio challenging the PUCO’s SEET decision.  In December 2012, the Supreme Court of Ohio issued an order which rejected all of the intervenors’ challenges and affirmed the PUCO decision.
 
169
 

The 2009 SEET order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm.  In January 2013, the PUCO found there was not a need for the large solar farm.  The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project by the end of 2013.  Management continues to evaluate other investment alternatives.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings, which included off-system sales in the SEET calculation.  In December 2011, the PUCO staff filed testimony that recommended a $23 million refund of 2010 earnings.  OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO-ordered SEET refund.  OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis.  The PUCO approved OPCo’s requests to file the SEET for 2011 and 2012 one month after the PUCO issues an order on the 2010 SEET.  Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in 2012 for OPCo.  Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo.

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover deferred fuel costs in rates beginning September 2012.  The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin.  In November 2012, OPCo filed an appeal at the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate.  The IEU and the Ohio Consumers’ Counsel also filed appeals at the Supreme Court of Ohio in November 2012 arguing that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues and reduced carrying costs due to an accumulated deferred income tax credit.  These appeals could reduce OPCo’s net deferred fuel balance up to the total balance, which could reduce future net income and cash flows.  A decision from the Supreme Court of Ohio is pending.

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

June 2012 – May 2015 ESP Including Capacity Charge

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

As part of the ESP decision, the PUCO ordered OPCo to conduct an energy-only auction for 10% of the SSO load with delivery beginning six months after the receipt of final orders in both the ESP and corporate separation cases and extending through May 2015.  The initiation of the auction is pending the issuance of an order by the PUCO in a separate docket.  The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning June 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015.  OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015.

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 June 30, 2013,  OPCo’s incurred deferred capacity costs balance of $171 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR is expected to provide approximately $500 million of revenue over the ESP period and will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs.  In August 2012, the IEU filed an action with the Supreme Court of Ohio stating, among other things, that OPCo’s collection of its capacity costs is illegal.  In April 2013, the Supreme Court of Ohio dismissed the IEU’s action.
 
170
 

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

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).  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. 

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

Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets at net book value to AEPGenCo.  AEPGenCo will also assume the associated generation liabilities.  In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.

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

Storm Damage Recovery Rider (SDRR)

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

2009 Fuel Adjustment Clause Audit

The PUCO selected an outside consultant to conduct an audit of OPCo’s FAC for 2009.  The outside consultant provided its audit report to the PUCO.  In January 2012, the PUCO ordered that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance.  In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges.  OPCo recorded a $30 million net favorable adjustment on the statement of income in the second quarter of 2012.  The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.  Management is unable to predict the outcome of any future consultant recommendation regarding valuation of the coal reserve.  If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.
 
171
 

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

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes.  As of June 30, 2013, the amount of OPCo’s carrying costs that could potentially be reduced due to the accumulated income tax issue is estimated to be $34 million, including $18 million of unrecognized equity carrying costs.  These amounts include the carrying costs exposure of the 2009 FAC audit, which has been appealed by an intervenor to the Supreme Court of Ohio.  Decisions from the PUCO are pending.  Management is unable to predict the outcome of these proceedings.  If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet.  This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009.  In March 2009, the PUCO approved a FAC in the ESP filing and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio.  The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record a regulatory asset for the difference between the approved market price and the rate paid by Ormet.  Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs.  In November 2009, OPCo requested that the PUCO approve recovery of the deferral under the interim agreement plus a weighted average cost of capital carrying charge.  The deferral amount is included in OPCo’s FAC phase-in deferral balance.  In the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related regulatory asset and requested that the PUCO prevent OPCo from collecting the Ormet-related revenues in the future.  The PUCO did not take any action on this request.  The intervenors raised the issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.  This issue remains pending before the PUCO.  If OPCo is not ultimately permitted to fully recover its requested deferrals under the interim arrangement, it could reduce future net income and cash flows and impact financial condition.

Special Rate Mechanism for Ormet

In October 2012, the PUCO issued an order approving a delayed payment plan for Ormet’s October and November 2012 power billings totaling $27 million to be paid in equal monthly installments over the period January 2014 to May 2015 without interest.  In the event Ormet does not pay its $27 million obligation, the PUCO permitted OPCo to recover the unpaid balance, up to $20 million, in the economic development rider.  To the extent unpaid amounts exceed $20 million, it could reduce future net income and cash flows and impact financial condition.

In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware but is current on all payments due to OPCo.  In June 2013, Ormet filed a motion with the PUCO to amend its contract with OPCo which currently provides for services through 2018.  The proposed amendments would allow Ormet to purchase power from a third party beginning January 2014.  In July 2013, OPCo filed its objections with the PUCO which included a recommendation to have Ormet pay an exit fee as a potential resolution to address the financial concerns associated with amending the current contract.  Hearings at the PUCO are scheduled for August 2013.  As of June 30, 2013, OPCo has a regulatory asset of $20 million and a net receivable of $6 million recorded related to the special rate mechanism for Ormet.
 
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Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  As of June 30, 2013, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order.  Intervenors have filed motions with the PUCO requesting OPCo refund all collected pre-construction costs to Ohio ratepayers with interest.

Management cannot predict the outcome of these proceedings concerning the Ohio IGCC plant or what effect, if any, these proceedings could have on future net income and cash flows.  However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.  As of June 30, 2013, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital cost cap, SWEPCo has capitalized approximately $1.8 billion of expenditures, including AFUDC and capitalized interest of $328 million and related transmission costs of $118 million.

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

The PUCT approved a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers.  SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful.  The Texas Industrial Energy Consumers (TIEC) filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers.  The Texas District Court and the Texas Court of Appeals affirmed the PUCT’s order in all respects.  In April 2012, SWEPCo and the TIEC filed petitions for review at the Supreme Court of Texas, which were denied in March 2013.  In April 2013, SWEPCo and the TIEC filed motions for rehearing at the Supreme Court of Texas.  In May 2013, the Supreme Court of Texas requested the PUCT and the TIEC respond to SWEPCo’s motion.

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.

2012 Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million, primarily due to the Turk Plant, based upon an 11.25% return on common equity to be effective January 2013.  The requested base rate increase included a return on and of the Texas jurisdictional share (approximately 33%) of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs.  The filing also (a) increased depreciation expense due to the decrease in the average remaining life of the Welsh Plant to account for the change in the retirement date of the Welsh Plant, Unit 2 from 2040 to 2016, (b) proposed increased vegetation management expenditures and (c) included a return on and of the Stall Unit as of December 2011 and associated operation and maintenance costs.
 
173
 

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 December 2012, several intervenors, including the PUCT staff, filed testimony that recommended an annual base rate increase between $16 million and $51 million based upon a return on common equity between 9% and 9.55%.  In addition, two intervenors recommended that the Turk Plant be excluded from rate base.  In May 2013, the ALJ issued a proposal for decision (PFD) and added clarifications in July 2013.  The PFD, as clarified, made various recommendations including (a) an annual base rate increase of approximately $41 million based upon a return on common equity of 9.65%, (b) the disallowance of the Turk Plant capital costs in excess of the investment and committed costs as of June 2010 plus the cost to retrofit Welsh Plant, Unit 2 which, as of June 30, 2013, SWEPCo estimates could result in a write-off of approximately $74 million (in excess of the $62 million reserve previously recorded related to the Texas capital cost cap) and (c) the exclusion, until SWEPCo’s next Texas base rate case, of the Turk Plant transmission line investment that was not in service at the end of the test year.  A decision from the PUCT is expected in the third quarter of 2013.  If the PUCT does not approve full cost recovery of SWEPCo’s Texas jurisdictional share of assets, it could reduce future net income and cash flows and impact financial condition.

2012 Louisiana Formula Rate Filing

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

Flint Creek Plant Environmental Controls

In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA.  The estimated cost of the project is $408 million, excluding AFUDC and company overheads.  As a joint owner of the Flint Creek Plant, SWEPCo’s portion of those costs is estimated at $204 million.  As of June 30, 2013, SWEPCo has incurred $24 million related to this project, including AFUDC and company overheads.  In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant.

APCo Rate Matters

Plant Transfers

In October 2012, the AEP East Companies submitted several filings with the FERC regarding the transfer of certain generation plants within the AEP System.  See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.  In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant, comprising 1,647 MW of average annual generating capacity presently owned by OPCo.  In April 2013, several intervenors filed testimony with the Virginia SCC and made recommendations relating to APCo’s proposed asset transfers including the issuance of a Request for Proposal (RFP) for APCo’s resource needs.  In May 2013, Virginia SCC staff filed testimony making recommendations including several alternatives to the asset transfers as proposed including the recommendation to approve only the Amos Plant, Unit 3 asset transfer and limiting the non-contractual liabilities to be assumed by APCo.  Hearings were held at the Virginia SCC in June 2013.  In June 2013, intervenors filed testimony with the WVPSC and made recommendations relating to APCo’s proposed asset transfers including the transfer of only one plant, the issuance
 
 
174
 
of a RFP for any additional capacity and energy requirements and limiting the liabilities to the types and amounts reflected in the net book value of the asset transfers.  Hearings were held at the WVPSC in July 2013.  APCo is currently pursuing cost recovery of these plants in West Virginia and plans to pursue cost recovery in Virginia.  If APCo and WPCo are not ultimately permitted to recover their incurred costs, it could reduce future net income and cash flows and impact financial condition.

APCo IGCC Plant

As of June 30, 2013, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $10 million applicable to its Virginia jurisdiction.  If the costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs effective February 2014 over a one-year period.  In March 2013, the environmental RAC surcharge expired related to the collection of 2009 and 2010 environmental compliance costs.  APCo has deferred $28 million as of June 30, 2013 for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $11 million of unrecognized equity carrying costs.  Hearings at the Virginia SCC are scheduled for August 2013.  If the Virginia SCC were to disallow any portion of the environmental RAC, it could reduce future net income and cash flows.

2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing

In March 2013, APCo filed with the Virginia SCC for an increase in its generation RAC revenues of $12 million for a total of $38 million annually to collect costs related to the Dresden Plant.  The generation RAC increase is expected to be effective in March 2014.  APCo has deferred $4 million as of June 30, 2013 for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $4 million of unrecognized equity carrying costs.  Hearings at the Virginia SCC are scheduled for August 2013.  If the Virginia SCC were to disallow any portion of the generation RAC, it could reduce future net income and cash flows.

2012 West Virginia Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation which allows the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred ENEC balances and other ENEC-related assets.  In August 2012, APCo and WPCo filed a request with the WVPSC for a financing order to securitize a total of $422 million related to the December 2011 under-recovered ENEC deferral balance including other ENEC-related assets of $13 million and related future financing costs of $7 million.  Upon completion of the securitization, APCo would offset its current ENEC rates by an amount to recover the securitized balance over the securitization period.  In March 2013, APCo, WPCo and intervenors filed a settlement agreement with the WVPSC which recommended the WVPSC authorize APCo to securitize $376 million plus upfront financing costs.  Hearings at the WVPSC on the securitization are scheduled for July 2013.  As of June 30, 2013, APCo’s ENEC under-recovery balance of $287 million, net of 2012 and 2013 over-recovery, was recorded in Regulatory Assets on the balance sheet, excluding $3 million of unrecognized equity carrying costs and $15 million of other ENEC-related assets.

In April 2013, APCo and WPCo filed to keep total rates unchanged with a portion of the ENEC to be specifically identified for the amount to be securitized in accordance with the proposed securitization settlement agreement.  The remaining ENEC rate is proposed to include (a) the proposed transfer of certain generation facilities from OPCo and the APCo/WPCo merger, (b) construction surcharges and (c) ongoing ENEC costs.  Management is currently reviewing intervenor testimony filed in July 2013 that recommends lower ENEC revenues.  Hearings at the WVPSC are scheduled for August 2013.  If the WVPSC were to disallow any portion of the ENEC, it could reduce future net income and cash flows.
 
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Virginia Storm Costs

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

WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting approval to merge WPCo into APCo.  In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC.  In April 2013, the FERC approved the WPCo merger into APCo.  In May 2013, Virginia SCC staff filed testimony that included a recommendation that the Virginia SCC not approve the proposed merger as there is no qualitative benefit and the impact on Virginia rates cannot be determined.  Hearings were held at the Virginia SCC in June 2013.  In June 2013, the WVPSC issued an order consolidating this case with APCo’s plant asset transfer case.  In June 2013, WVPSC staff filed testimony that included a recommendation that the WVPSC approve the proposed merger.  Hearings were held at the WVPSC in July 2013.  See the “Plant Transfers” section of APCo Rate Matters and the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.

PSO Rate Matters

Oklahoma Environmental Compliance Plan

In September 2012, based upon an agreement with the Federal EPA, the State of Oklahoma and other parties, 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.  The plan requested approval for (a) an estimated $210 million of new environmental investment, excluding AFUDC and overheads of $46 million, that will be incurred prior to 2016 at NES Unit 3, (b) accelerated recovery through 2026 of the net book value of NES Units 3 and 4 (combined net book value of the two units is $231 million as of June 30, 2013), (c) an estimated $83 million of new investment incurred through 2016 at various gas units and (d) a new 15-year purchase power agreement (PPA) with a nonaffiliated entity, effective in 2016, with cost recovery through a rider, including an annual earnings component of $3 million.  Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery in a future rate proceeding.

In January 2013, testimony filed by the OCC staff and the Oklahoma Office of the Attorney General (OOAG) recommended no earnings component on the PPA and to delay final decisions until 2020 on parts of the plan including cost recovery of the net book value of NES Unit 3 and any increases in fuel costs due to reductions in the output of energy from NES Unit 3 beginning in 2021.  The testimony recommended that cost recovery could extend past 2026 on parts of the plan and recommended a $175 million cost cap on NES Unit 3 environmental investment, excluding AFUDC and overheads.

In March 2013, the OCC staff and the OOAG filed additional testimony revising the recommended cost cap on NES Unit 3 to $210 million, excluding AFUDC and overheads, and recommended conditional approval of the planned NES Unit 3 retirement subject to OCC approval in 2020 provided the planned retirement is consistent with environmental rules at that time.

Also, an intervenor representing some of PSO’s large industrial users opposed the majority of PSO’s plan, including recommending no cost recovery of NES Units 3 and 4 book value amounts not recovered at the time of their retirement and no recovery of the PPA costs, including earnings on the PPA.  In February 2013, the OCC staff requested a stay in this proceeding, which was granted by the OCC in March 2013.  In July 2013, the OCC staff filed a motion to lift the stay and dismiss PSO's environmental compliance plan case without prejudice.  A hearing on the motion will be held in August 2013.  If this case is dismissed, 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.
 
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I&M Rate Matters

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%.  In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates from $85 million to $92 million.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed a request for reconsideration with the IURC, which was denied.  Also in March 2013, the OUCC filed an appeal of the order with the Indiana Court of Appeals.  If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of June 30, 2013, I&M has incurred $240 million related to the LCM Project, including AFUDC.

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

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.  If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

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 of the units at the Rockport Plant with a Dry Sorbent Injection system.  The estimated cost of the CCT Project was $285 million, excluding AFUDC, of which I&M’s ownership share is $142 million.  The application requested deferral treatment of any unrecovered carrying costs incurred during construction and incremental post in-service depreciation expense and operation and maintenance expenses until such costs are recognized and recovered in a rider.  I&M also requested cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism.
 
In July 2013, a settlement agreement was filed with the IURC.  The settlement agreement includes the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s direct ownership share of $129 million.  The settlement agreement specifies that 80% of the recoverable I&M direct ownership share of CCT Project costs will be recovered through a Federal Mandate Rider with the remaining 20% deferred until rates are established in a subsequent rate case.  If the IURC approves the settlement agreement, I&M’s Indiana allocated share of the CCT Project costs received in the form of purchased power from AEGCo will be recovered in subsequent I&M rate cases.  Hearings at the IURC are scheduled for August 2013.  A decision is expected by November 2013.  As of June 30, 2013, I&M has incurred costs of $39 million related to the CCT Project, including AFUDC.  If I&M is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows.
 
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FERC Rate Matters

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

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

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

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

4.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business.  In addition, their business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements.  The Commitments, Guarantees and Contingencies note within the 2012 Annual Report should be read in conjunction with this report.

GUARANTEES

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

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

Certain Registrant Subsidiaries enter into standby letters of credit with third parties.  These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves.
 
178
 

AEP has two credit facilities totaling $3.5 billion, under which up to $1.2 billion may be issued as letters of credit. As of June 30, 2013, the maximum future payments for letters of credit issued under the credit facilities were as follows:

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

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

         
Bilateral
  
Maturity of
   
Pollution
  
Letters
  
Bilateral Letters
Company
  
Control Bonds
  
of Credit
  
of Credit
   
(in thousands)
    
APCo
  
$
229,650 
  
$
 232,293 
  
March 2014 to March 2015
I&M
    
77,000 
    
 77,886 
  
March 2015
OPCo
    
50,000 
    
 50,575 
  
July 2014

Guarantees of Third-Party Obligations – Affecting SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation.  As of June 30, 2013, SWEPCo has collected approximately $62 million through a rider for final mine closure and reclamation costs, of which $12 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $50 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed balance sheets.

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

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

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of June 30, 2013, there were no material liabilities recorded for any indemnifications.

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

The Registrant Subsidiaries lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.  As of June 30, 2013, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:

   
Maximum
Company
  
Potential Loss
   
(in thousands)
APCo
  
$
 3,639 
I&M
    
 2,495 
OPCo
    
 4,543 
PSO
    
 1,202 
SWEPCo
    
 2,442 

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignments are accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $13 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2013.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 83% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  The maximum potential losses related to the guarantee are approximately $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, management believes that the fair value would produce a sufficient sales price to avoid any loss.

ENVIRONMENTAL CONTINGENCIES

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

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing.  An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place.  Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision.  The petition was denied in January 2011.  Plaintiffs refiled their complaint in federal district court.  The court ordered all defendants to respond to the refiled complaints in October 2011.  In March 2012, the court granted the defendants’ motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations.  In May 2013, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court’s dismissal of the complaint.  The plaintiffs may seek further review in the U.S. Supreme Court.  Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.
 
180
 

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

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court’s decision, holding that the CAA displaced Kivalina’s claims for damages.  Plaintiffs filed seeking further review in the U.S. Supreme Court.  In May 2013, the U.S. Supreme Court denied the plaintiffs’ request for review.

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

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

In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M started remediation work in accordance with a plan approved by MDEQ.  I&M’s reserve is approximately $10 million.  As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ.  Management cannot predict the amount of additional cost, if any.

NUCLEAR CONTINGENCIES – AFFECTING I&M

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

Nuclear Incident Insurance

Prior to April 2013, I&M carried insurance coverage for a nuclear or nonnuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion.  Effective April 2013, insurance coverage for a nonnuclear incident at the Cook Plant was reduced to $1.7 billion.  In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition.
 
181
 

5.  DISPOSITION AND IMPAIRMENT

DISPOSITION

2013

Conesville Coal Preparation Plant – Affecting OPCo

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

IMPAIRMENT

2013

Muskingum River Plant, Unit 5 – Affecting OPCo

In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including OPCo’s 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant.  Under the modification to the consent decree, OPCo has the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017.  In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, management re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project which would have extended the useful life of MR5 is remote.  As a result, management completed an impairment analysis and concluded that MR5 was impaired.  Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit.  In the second quarter of 2013, OPCo recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory.  Management expects to retire the plant in 2015.
 
182
 

6.  BENEFIT PLANS

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

Components of Net Periodic Benefit Cost

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

APCo
                      
     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Three Months Ended June 30,
  
Three Months Ended June 30,
 
2013 
  
2012 
  
2013 
  
2012 
 
(in thousands)
Service Cost
$
 1,542 
  
$
 1,891 
  
$
 642 
  
$
 1,347 
Interest Cost
  
 6,915 
    
 7,553 
    
 3,364 
    
 4,615 
Expected Return on Plan Assets
  
 (9,260)
    
 (10,486)
    
 (4,537)
    
 (4,188)
Amortization of Transition Obligation
  
 - 
    
 - 
    
 - 
    
 200 
Amortization of Prior Service Cost (Credit)
  
 50 
    
 119 
    
 (2,513)
    
 (715)
Amortization of Net Actuarial Loss
  
 6,257 
    
 5,084 
    
 3,062 
    
 2,632 
Net Periodic Benefit Cost
$
 5,504 
  
$
 4,161 
  
$
 18 
  
$
 3,891 

     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Six Months Ended June 30,
  
Six Months Ended June 30,
 
2013 
  
2012 
  
2013 
  
2012 
 
(in thousands)
Service Cost
$
 3,085 
  
$
 3,782 
  
$
 1,283 
  
$
 2,694 
Interest Cost
  
 13,831 
    
 15,106 
    
 6,727 
    
 9,231 
Expected Return on Plan Assets
  
 (18,520)
    
 (20,972)
    
 (9,073)
    
 (8,376)
Amortization of Transition Obligation
  
 - 
    
 - 
    
 - 
    
 400 
Amortization of Prior Service Cost (Credit)
  
 99 
    
 238 
    
 (5,025)
    
 (1,431)
Amortization of Net Actuarial Loss
  
 12,513 
    
 10,169 
    
 6,124 
    
 5,263 
Net Periodic Benefit Cost
$
 11,008 
  
$
 8,323 
  
$
 36 
  
$
 7,781 

 
183
 
I&M
                      
     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Three Months Ended June 30,
  
Three Months Ended June 30,
 
2013 
  
2012 
  
2013 
  
2012 
 
(in thousands)
Service Cost
$
 2,184 
  
$
 2,477 
  
$
 805 
  
$
 1,655 
Interest Cost
  
 6,025 
    
 6,561 
    
 2,055 
    
 3,197 
Expected Return on Plan Assets
  
 (8,206)
    
 (9,392)
    
 (3,296)
    
 (3,212)
Amortization of Transition Obligation
  
 - 
    
 - 
    
 - 
    
 33 
Amortization of Prior Service Cost (Credit)
  
 48 
    
 102 
    
 (2,355)
    
 (596)
Amortization of Net Actuarial Loss
  
 5,422 
    
 4,393 
    
 1,881 
    
 1,763 
Net Periodic Benefit Cost (Credit)
$
 5,473 
  
$
 4,141 
  
$
 (910)
  
$
 2,840 

     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Six Months Ended June 30,
  
Six Months Ended June 30,
 
2013 
  
2012 
  
2013 
  
2012 
 
(in thousands)
Service Cost
$
 4,368 
  
$
 4,954 
  
$
 1,610 
  
$
 3,310 
Interest Cost
  
 12,050 
    
 13,122 
    
 4,110 
    
 6,393 
Expected Return on Plan Assets
  
 (16,413)
    
 (18,783)
    
 (6,592)
    
 (6,423)
Amortization of Transition Obligation
  
 - 
    
 - 
    
 - 
    
 66 
Amortization of Prior Service Cost (Credit)
  
 97 
    
 204 
    
 (4,710)
    
 (1,192)
Amortization of Net Actuarial Loss
  
 10,844 
    
 8,785 
    
 3,763 
    
 3,525 
Net Periodic Benefit Cost (Credit)
$
 10,946 
  
$
 8,282 
  
$
 (1,819)
  
$
 5,679 

OPCo
                      
     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Three Months Ended June 30,
  
Three Months Ended June 30,
 
2013 
  
2012 
  
2013 
  
2012 
 
(in thousands)
Service Cost
$
 2,373 
  
$
 2,751 
  
$
 1,299 
  
$
 2,187 
Interest Cost
  
 10,292 
    
 11,299 
    
 4,447 
    
 6,048 
Expected Return on Plan Assets
  
 (15,142)
    
 (17,101)
    
 (6,239)
    
 (5,639)
Amortization of Transition Obligation
  
 - 
    
 - 
    
 - 
    
 26 
Amortization of Prior Service Cost (Credit)
  
 70 
    
 185 
    
 (3,230)
    
 (968)
Amortization of Net Actuarial Loss
  
 9,309 
    
 7,610 
    
 4,041 
    
 3,417 
Net Periodic Benefit Cost
$
 6,902 
  
$
 4,744 
  
$
 318 
  
$
 5,071 

     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Six Months Ended June 30,
  
Six Months Ended June 30,
 
2013 
  
2012 
  
2013 
  
2012 
 
(in thousands)
Service Cost
$
 4,745 
  
$
 5,502 
  
$
 2,599 
  
$
 4,374 
Interest Cost
  
 20,584 
    
 22,597 
    
 8,894 
    
 12,095 
Expected Return on Plan Assets
  
 (30,283)
    
 (34,201)
    
 (12,477)
    
 (11,278)
Amortization of Transition Obligation
  
 - 
    
 - 
    
 - 
    
 52 
Amortization of Prior Service Cost (Credit)
  
 141 
    
 371 
    
 (6,461)
    
 (1,936)
Amortization of Net Actuarial Loss
  
 18,618 
    
 15,220 
    
 8,082 
    
 6,834 
Net Periodic Benefit Cost
$
 13,805 
  
$
 9,489 
  
$
 637 
  
$
 10,141 

 
184
 
PSO
                      
     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Three Months Ended June 30,
  
Three Months Ended June 30,
 
2013 
  
2012 
  
2013 
  
2012 
 
(in thousands)
Service Cost
$
 1,390 
  
$
 1,488 
  
$
 343 
  
$
 709 
Interest Cost
  
 2,749 
    
 3,075 
    
 948 
    
 1,450 
Expected Return on Plan Assets
  
 (3,919)
    
 (4,504)
    
 (1,522)
    
 (1,481)
Amortization of Prior Service Cost (Credit)
  
 74 
    
 (237)
    
 (1,073)
    
 (269)
Amortization of Net Actuarial Loss
  
 2,461 
    
 2,051 
    
 869 
    
 797 
Net Periodic Benefit Cost (Credit)
$
 2,755 
  
$
 1,873 
  
$
 (435)
  
$
 1,206 

     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Six Months Ended June 30,
  
Six Months Ended June 30,
 
2013 
  
2012 
  
2013 
  
2012 
 
(in thousands)
Service Cost
$
 2,781 
  
$
 2,976 
  
$
 686 
  
$
 1,418 
Interest Cost
  
 5,497 
    
 6,150 
    
 1,896 
    
 2,899 
Expected Return on Plan Assets
  
 (7,837)
    
 (9,008)
    
 (3,044)
    
 (2,961)
Amortization of Prior Service Cost (Credit)
  
 148 
    
 (474)
    
 (2,145)
    
 (539)
Amortization of Net Actuarial Loss
  
 4,922 
    
 4,103 
    
 1,738 
    
 1,594 
Net Periodic Benefit Cost (Credit)
$
 5,511 
  
$
 3,747 
  
$
 (869)
  
$
 2,411 

SWEPCo
                      
     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Three Months Ended June 30,
  
Three Months Ended June 30,
 
2013 
  
2012 
  
2013 
  
2012 
 
(in thousands)
Service Cost
$
 1,753 
  
$
 1,774 
  
$
 423 
  
$
 831 
Interest Cost
  
 2,863 
    
 3,135 
    
 1,076 
    
 1,668 
Expected Return on Plan Assets
  
 (4,128)
    
 (4,716)
    
 (1,720)
    
 (1,698)
Amortization of Prior Service Cost (Credit)
  
 88 
    
 (199)
    
 (1,290)
    
 (233)
Amortization of Net Actuarial Loss
  
 2,554 
    
 2,082 
    
 982 
    
 914 
Net Periodic Benefit Cost (Credit)
$
 3,130 
  
$
 2,076 
  
$
 (529)
  
$
 1,482 

     
Other Postretirement
 
Pension Plans
  
Benefit Plans
 
Six Months Ended June 30,
  
Six Months Ended June 30,
 
2013 
  
2012 
  
2013 
  
2012 
 
(in thousands)
Service Cost
$
 3,506 
  
$
 3,549 
  
$
 846 
  
$
 1,662 
Interest Cost
  
 5,727 
    
 6,269 
    
 2,151 
    
 3,336 
Expected Return on Plan Assets
  
 (8,255)
    
 (9,433)
    
 (3,440)
    
 (3,397)
Amortization of Prior Service Cost (Credit)
  
 175 
    
 (397)
    
 (2,578)
    
 (466)
Amortization of Net Actuarial Loss
  
 5,107 
    
 4,165 
    
 1,964 
    
 1,829 
Net Periodic Benefit Cost (Credit)
$
 6,260 
  
$
 4,153 
  
$
 (1,057)
  
$
 2,964 

7.  BUSINESS SEGMENTS

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

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries.  To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options.  Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.”  Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business.  AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio.   For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities.  AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies.  For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.”  The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors.
 
186
 

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

Notional Volume of Derivative Instruments
June 30, 2013
                                       
Primary Risk
  
Unit of
                              
Exposure
  
Measure
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
           
(in thousands)
Commodity:
                                  
 
Power
  
MWhs
    
 99,667 
    
 68,875 
    
 140,924 
    
 9 
    
 10 
 
Coal
  
Tons
    
 502 
    
 1,607 
    
 1,372 
    
 946 
    
 795 
 
Natural Gas
  
MMBtus
    
 6,120 
    
 4,230 
    
 8,654 
    
 - 
    
 - 
 
Heating Oil and
                                  
   
Gasoline
  
Gallons
    
 883 
    
 435 
    
 1,039 
    
 442 
    
 543 
 
Interest Rate
  
USD
  
$
 18,121 
  
$
 12,523 
  
$
 25,622 
  
$
 - 
  
$
 - 
                                       
Interest Rate and
                                  
 
Foreign Currency
  
USD
  
$
 - 
  
$
 - 
  
$
 - 
  
$
 - 
  
$
 - 
                                       
Notional Volume of Derivative Instruments
December 31, 2012
                                       
Primary Risk
  
Unit of
                              
Exposure
  
Measure
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
           
(in thousands)
Commodity:
                                  
 
Power
  
MWhs
    
 94,059 
    
 64,791 
    
 132,188 
    
 - 
    
 - 
 
Coal
  
Tons
    
 1,401 
    
 2,711 
    
 3,033 
    
 1,980 
    
 1,312 
 
Natural Gas
  
MMBtus
    
 10,077 
    
 6,922 
    
 14,163 
    
 - 
    
 - 
 
Heating Oil and
                                  
   
Gasoline
  
Gallons
    
 1,050 
    
 532 
    
 1,260 
    
 616 
    
 585 
 
Interest Rate
  
USD
  
$
 24,146 
  
$
 16,584 
  
$
 33,934 
  
$
 - 
  
$
 - 
                                       
Interest Rate and
                                  
 
Foreign Currency
  
USD
  
$
 - 
  
$
 200,000 
  
$
 - 
  
$
 - 
  
$
 - 

Fair Value Hedging Strategies

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

Cash Flow Hedging Strategies

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

The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility.  AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases.  For disclosure purposes, these contracts are included with other hedging activities as “Commodity.”  The Registrant Subsidiaries do not hedge all fuel price risk.
 
187
 

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

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

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

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

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

According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the June 30, 2013 and December 31, 2012 condensed balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

     
June 30, 2013
  
December 31, 2012
     
Cash Collateral
  
Cash Collateral
  
Cash Collateral
  
Cash Collateral
     
Received
  
Paid
  
Received
  
Paid
     
Netted Against
  
Netted Against
  
Netted Against
  
Netted Against
     
Risk Management
  
Risk Management
  
Risk Management
  
Risk Management
Company
  
Assets
  
Liabilities
  
Assets
  
Liabilities
     
(in thousands)
APCo
  
$
 555 
  
$
 5,021 
  
$
 1,262 
  
$
 11,029 
I&M
    
 383 
    
 3,455 
    
 867 
    
 7,576 
OPCo
    
 784 
    
 7,081 
    
 1,774 
    
 15,500 
PSO
    
 - 
    
 35 
    
 - 
    
 - 
SWEPCo
    
 - 
    
 44 
    
 - 
    
 - 

 
188
 


The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of June 30, 2013 and December 31, 2012:

APCo
                                    
Fair Value of Derivative Instruments
June 30, 2013
                                       
     
Risk
          
Gross Amounts
  
Gross
  
Net Amounts of
     
Management
          
of Risk
  
Amounts
  
Assets/Liabilities
     
Contracts
  
Hedging Contracts
  
Management
  
Offset in the
  
Presented in the
               
Interest Rate
  
Assets/
  
Statement of
  
Statement of
             
and Foreign
  
Liabilities
  
Financial
  
Financial
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Recognized
  
Position (b)
  
Position (c)
     
(in thousands)
Current Risk Management Assets
  
$
86,770 
  
$
995 
  
$
- 
  
$
87,765 
  
$
(59,245)
  
$
28,520 
Long-term Risk Management Assets
    
38,563 
    
- 
    
- 
    
38,563 
    
(14,955)
    
23,608 
Total Assets
    
125,333 
    
995 
    
- 
    
126,328 
    
(74,200)
    
52,128 
                                       
Current Risk Management Liabilities
    
75,377 
    
679 
    
- 
    
76,056 
    
(62,659)
    
13,397 
Long-term Risk Management Liabilities
    
29,990 
    
24 
    
- 
    
30,014 
    
(16,007)
    
14,007 
Total Liabilities
    
105,367 
    
703 
    
- 
    
106,070 
    
(78,666)
    
27,404 
                                       
Total MTM Derivative Contract Net
                                    
 
Assets (Liabilities)
  
$
19,966 
  
$
292 
  
$
- 
  
$
20,258 
  
$
4,466 
  
$
24,724 
                                       
APCo
                                    
Fair Value of Derivative Instruments
December 31, 2012
                                       
     
Risk
          
Gross Amounts
  
Gross
  
Net Amounts of
     
Management
          
of Risk
  
Amounts
  
Assets/Liabilities
     
Contracts
  
Hedging Contracts
  
Management
  
Offset in the
  
Presented in the
               
Interest Rate
  
Assets/
  
Statement of
  
Statement of
             
and Foreign
  
Liabilities
  
Financial
  
Financial
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Recognized
  
Position (b)
  
Position (c)
     
(in thousands)
Current Risk Management Assets
  
$
127,645 
  
$
338 
  
$
- 
  
$
127,983 
  
$
(97,023)
  
$
30,960 
Long-term Risk Management Assets
    
60,498 
    
215 
    
- 
    
60,713 
    
(26,353)
    
34,360 
Total Assets
    
188,143 
    
553 
    
- 
    
188,696 
    
(123,376)
    
65,320 
                                       
Current Risk Management Liabilities
    
119,430 
    
1,182 
    
- 
    
120,612 
    
(103,914)
    
16,698 
Long-term Risk Management Liabilities
    
47,281 
    
424 
    
- 
    
47,705 
    
(29,229)
    
18,476 
Total Liabilities
    
166,711 
    
1,606 
    
- 
    
168,317 
    
(133,143)
    
35,174 
                                       
Total MTM Derivative Contract Net
                                    
 
Assets (Liabilities)
  
$
21,432 
  
$
(1,053)
  
$
- 
  
$
20,379 
  
$
9,767 
  
$
30,146 

 
189
 


I&M
                                    
Fair Value of Derivative Instruments
June 30, 2013
                                       
     
Risk
          
Gross Amounts
  
Gross
  
Net Amounts of
     
Management
          
of Risk
  
Amounts
  
Assets/Liabilities
     
Contracts
  
Hedging Contracts
  
Management
  
Offset in the
  
Presented in the
               
Interest Rate
  
Assets/
  
Statement of
  
Statement of
             
and Foreign
  
Liabilities
  
Financial
  
Financial
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Recognized
  
Position (b)
  
Position (c)
     
(in thousands)
Current Risk Management Assets
  
$
59,657 
  
$
686 
  
$
- 
  
$
60,343 
  
$
(40,744)
  
$
19,599 
Long-term Risk Management Assets
    
26,650 
    
- 
    
- 
    
26,650 
    
(10,335)
    
16,315 
Total Assets
    
86,307 
    
686 
    
- 
    
86,993 
    
(51,079)
    
35,914 
                                       
Current Risk Management Liabilities
    
52,025 
    
455 
    
- 
    
52,480 
    
(43,093)
    
9,387 
Long-term Risk Management Liabilities
    
21,066 
    
12 
    
- 
    
21,078 
    
(11,058)
    
10,020 
Total Liabilities
    
73,091 
    
467 
    
- 
    
73,558 
    
(54,151)
    
19,407 
                                       
Total MTM Derivative Contract Net
                                    
 
Assets (Liabilities)
  
$
13,216 
  
$
219 
  
$
- 
  
$
13,435 
  
$
3,072 
  
$
16,507 
                                       
I&M
                                    
Fair Value of Derivative Instruments
December 31, 2012
                                     
     
Risk
          
Gross Amounts
  
Gross
  
Net Amounts of
     
Management
          
of Risk
  
Amounts
  
Assets/Liabilities
     
Contracts
  
Hedging Contracts
  
Management
  
Offset in the
  
Presented in the
               
Interest Rate
  
Assets/
  
Statement of
  
Statement of
             
and Foreign
  
Liabilities
  
Financial
  
Financial
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Recognized
  
Position (b)
  
Position (c)
     
(in thousands)
Current Risk Management Assets
  
$
93,268 
  
$
220 
  
$
- 
  
$
93,488 
  
$
(66,514)
  
$
26,974 
Long-term Risk Management Assets
    
41,553 
    
148 
    
- 
    
41,701 
    
(18,132)
    
23,569 
Total Assets
    
134,821 
    
368 
    
- 
    
135,189 
    
(84,646)
    
50,543 
                                       
Current Risk Management Liabilities
    
82,433 
    
807 
    
19,524 
    
102,764 
    
(71,247)
    
31,517 
Long-term Risk Management Liabilities
    
33,714 
    
292 
    
- 
    
34,006 
    
(20,108)
    
13,898 
Total Liabilities
    
116,147 
    
1,099 
    
19,524 
    
136,770 
    
(91,355)
    
45,415 
                                       
Total MTM Derivative Contract Net
                                    
 
Assets (Liabilities)
  
$
18,674 
  
$
(731)
  
$
(19,524)
  
$
(1,581)
  
$
6,709 
  
$
5,128 

 
190
 


OPCo
                                    
Fair Value of Derivative Instruments
June 30, 2013
                                       
     
Risk
          
Gross Amounts
  
Gross
  
Net Amounts of
     
Management
          
of Risk
  
Amounts
  
Assets/Liabilities
     
Contracts
  
Hedging Contracts
  
Management
  
Offset in the
  
Presented in the
               
Interest Rate
  
Assets/
  
Statement of
  
Statement of
             
and Foreign
  
Liabilities
  
Financial
  
Financial
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Recognized
  
Position (b)
  
Position (c)
     
(in thousands)
Current Risk Management Assets
  
$
126,809 
  
$
1,406 
  
$
- 
  
$
128,215 
  
$
(87,070)
  
$
41,145 
Long-term Risk Management Assets
    
54,528 
    
- 
    
- 
    
54,528 
    
(21,147)
    
33,381 
Total Assets
    
181,337 
    
1,406 
    
- 
    
182,743 
    
(108,217)
    
74,526 
                                       
Current Risk Management Liabilities
    
110,711 
    
943 
    
- 
    
111,654 
    
(91,885)
    
19,769 
Long-term Risk Management Liabilities
    
42,403 
    
29 
    
- 
    
42,432 
    
(22,629)
    
19,803 
Total Liabilities
    
153,114 
    
972 
    
- 
    
154,086 
    
(114,514)
    
39,572 
                                       
Total MTM Derivative Contract Net
                                    
 
Assets (Liabilities)
  
$
28,223 
  
$
434 
  
$
- 
  
$
28,657 
  
$
6,297 
  
$
34,954 
                                       
OPCo
                                    
Fair Value of Derivative Instruments
December 31, 2012
                                       
     
Risk
          
Gross Amounts
  
Gross
  
Net Amounts of
     
Management
          
of Risk
  
Amounts
  
Assets/Liabilities
     
Contracts
  
Hedging Contracts
  
Management
  
Offset in the
  
Presented in the
               
Interest Rate
  
Assets/
  
Statement of
  
Statement of
             
and Foreign
  
Liabilities
  
Financial
  
Financial
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Recognized
  
Position (b)
  
Position (c)
     
(in thousands)
Current Risk Management Assets
  
$
183,064 
  
$
464 
  
$
- 
  
$
183,528 
  
$
(139,215)
  
$
44,313 
Long-term Risk Management Assets
    
85,023 
    
303 
    
- 
    
85,326 
    
(37,038)
    
48,288 
Total Assets
    
268,087 
    
767 
    
- 
    
268,854 
    
(176,253)
    
92,601 
                                       
Current Risk Management Liabilities
    
171,397 
    
1,658 
    
- 
    
173,055 
    
(148,900)
    
24,155 
Long-term Risk Management Liabilities
    
66,448 
    
596 
    
- 
    
67,044 
    
(41,079)
    
25,965 
Total Liabilities
    
237,845 
    
2,254 
    
- 
    
240,099 
    
(189,979)
    
50,120 
                                       
Total MTM Derivative Contract Net
                                    
 
Assets (Liabilities)
  
$
30,242 
  
$
(1,487)
  
$
- 
  
$
28,755 
  
$
13,726 
  
$
42,481 

 
191
 


PSO
                                    
Fair Value of Derivative Instruments
June 30, 2013
                                       
     
Risk
          
Gross Amounts
  
Gross
  
Net Amounts of
     
Management
          
of Risk
  
Amounts
  
Assets/Liabilities
     
Contracts
  
Hedging Contracts
  
Management
  
Offset in the
  
Presented in the
               
Interest Rate
  
Assets/
  
Statement of
  
Statement of
             
and Foreign
  
Liabilities
  
Financial
  
Financial
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Recognized
  
Position (b)
  
Position (c)
     
(in thousands)
Current Risk Management Assets
  
$
1,289 
  
$
6 
  
$
- 
  
$
1,295 
  
$
(811)
  
$
484 
Long-term Risk Management Assets
    
- 
    
- 
    
- 
    
- 
    
- 
    
- 
Total Assets
    
1,289 
    
6 
    
- 
    
1,295 
    
(811)
    
484 
                                       
Current Risk Management Liabilities
    
2,910 
    
37 
    
- 
    
2,947 
    
(836)
    
2,111 
Long-term Risk Management Liabilities
    
- 
    
12 
    
- 
    
12 
    
(10)
    
2 
Total Liabilities
    
2,910 
    
49 
    
- 
    
2,959 
    
(846)
    
2,113 
                                       
Total MTM Derivative Contract Net
                                    
 
Assets (Liabilities)
  
$
(1,621)
  
$
(43)
  
$
- 
  
$
(1,664)
  
$
35 
  
$
(1,629)
                                       
PSO
                                    
Fair Value of Derivative Instruments
December 31, 2012
                                       
     
Risk
          
Gross Amounts
  
Gross
  
Net Amounts of
     
Management
          
of Risk
  
Amounts
  
Assets/Liabilities
     
Contracts
  
Hedging Contracts
  
Management
  
Offset in the
  
Presented in the
               
Interest Rate
  
Assets/
  
Statement of
  
Statement of
             
and Foreign
  
Liabilities
  
Financial
  
Financial
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Recognized
  
Position (b)
  
Position (c)
     
(in thousands)
Current Risk Management Assets
  
$
1,657 
  
$
42 
  
$
- 
  
$
1,699 
  
$
(1,190)
  
$
509 
Long-term Risk Management Assets
    
- 
    
- 
    
- 
    
- 
    
31 
    
31 
Total Assets
    
1,657 
    
42 
    
- 
    
1,699 
    
(1,159)
    
540 
                                       
Current Risk Management Liabilities
    
7,021 
    
17 
    
- 
    
7,038 
    
(1,190)
    
5,848 
Long-term Risk Management Liabilities
    
- 
    
- 
    
- 
    
- 
    
31 
    
31 
Total Liabilities
    
7,021 
    
17 
    
- 
    
7,038 
    
(1,159)
    
5,879 
                                       
Total MTM Derivative Contract Net
                                    
 
Assets (Liabilities)
  
$
(5,364)
  
$
25 
  
$
- 
  
$
(5,339)
  
$
- 
  
$
(5,339)

 
192
 


SWEPCo
                                    
Fair Value of Derivative Instruments
June 30, 2013
                                       
   
Risk
          
Gross Amounts
  
Gross
  
Net Amounts of
   
Management
          
of Risk
  
Amounts
  
Assets/Liabilities
   
Contracts
  
Hedging Contracts
  
Management
  
Offset in the
  
Presented in the
             
Interest Rate
  
Assets/
  
Statement of
  
Statement of
           
and Foreign
  
Liabilities
  
Financial
  
Financial
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Recognized
  
Position (b)
  
Position (c)
   
(in thousands)
Current Risk Management Assets
  
$
1,846 
  
$
6 
  
$
- 
  
$
1,852 
  
$
(1,454)
  
$
398 
Long-term Risk Management Assets
    
- 
    
- 
    
- 
    
- 
    
- 
    
- 
Total Assets
    
1,846 
    
6 
    
- 
    
1,852 
    
(1,454)
    
398 
                                     
Current Risk Management Liabilities
    
2,382 
    
45 
    
- 
    
2,427 
    
(1,486)
    
941 
Long-term Risk Management Liabilities
    
- 
    
15 
    
- 
    
15 
    
(12)
    
3 
Total Liabilities
    
2,382 
    
60 
    
- 
    
2,442 
    
(1,498)
    
944 
                                     
Total MTM Derivative Contract Net
                                    
 
Assets (Liabilities)
  
$
(536)
  
$
(54)
  
$
- 
  
$
(590)
  
$
44 
  
$
(546)
                                     
SWEPCo
                                    
Fair Value of Derivative Instruments
December 31, 2012
                                       
   
Risk
          
Gross Amounts
  
Gross
  
Net Amounts of
   
Management
          
of Risk
  
Amounts
  
Assets/Liabilities
   
Contracts
  
Hedging Contracts
  
Management
  
Offset in the
  
Presented in the
             
Interest Rate
  
Assets/
  
Statement of
  
Statement of
           
and Foreign
  
Liabilities
  
Financial
  
Financial
Balance Sheet Location
  
Commodity (a)
  
Commodity (a)
  
Currency (a)
  
Recognized
  
Position (b)
  
Position (c)
   
(in thousands)
Current Risk Management Assets
  
$
2,804 
  
$
41 
  
$
- 
  
$
2,845 
  
$
(2,150)
  
$
695 
Long-term Risk Management Assets
    
- 
    
- 
    
- 
    
- 
    
- 
    
- 
Total Assets
    
2,804 
    
41 
    
- 
    
2,845 
    
(2,150)
    
695 
                                     
Current Risk Management Liabilities
    
3,261 
    
17 
    
- 
    
3,278 
    
(2,150)
    
1,128 
Long-term Risk Management Liabilities
    
- 
    
- 
    
- 
    
- 
    
- 
    
- 
Total Liabilities
    
3,261 
    
17 
    
- 
    
3,278 
    
(2,150)
    
1,128 
                                     
Total MTM Derivative Contract Net
                                    
 
Assets (Liabilities)
  
$
(457)
  
$
24 
  
$
- 
  
$
(433)
  
$
- 
  
$
(433)

(a)
Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."
(b)
Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."
(c)
There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.

 
193
 


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

 
Amount of Gain (Loss) Recognized on
 
Risk Management Contracts
 
For the Three Months Ended June 30, 2013
   
 
Location of Gain (Loss)
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
         
(in thousands)
 
Electric Generation, Transmission and
                              
   
Distribution Revenues
  
$
 194 
  
$
 2,897 
  
$
 1,819 
  
$
 169 
  
$
 302 
 
Sales to AEP Affiliates
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
 
Fuel and Other Consumables Used for
                              
   
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
 
Regulatory Assets (a)
    
 (974)
    
 (1,585)
    
 (4,492)
    
 192 
    
 (373)
 
Regulatory Liabilities (a)
    
 1,230 
    
 (880)
    
 3,360 
    
 (1)
    
 39 
 
Total Gain (Loss) on Risk Management
                              
   
Contracts
  
$
 450 
  
$
 432 
  
$
 687 
  
$
 360 
  
$
 (32)
                                     
 
Amount of Gain (Loss) Recognized on
 
Risk Management Contracts
 
For the Three Months Ended June 30, 2012
   
 
Location of Gain (Loss)
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
         
(in thousands)
 
Electric Generation, Transmission and
                              
   
Distribution Revenues
  
$
 (599)
  
$
 2,579 
  
$
 2,538 
  
$
 165 
  
$
 303 
 
Sales to AEP Affiliates
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
 
Fuel and Other Consumables Used for
                              
   
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
 
Regulatory Assets (a)
    
 (3,796)
    
 (2,905)
    
 (8,895)
    
 (757)
    
 (364)
 
Regulatory Liabilities (a)
    
 4,711 
    
 392 
    
 7,178 
    
 (26)
    
 (27)
 
Total Gain (Loss) on Risk Management
                              
   
Contracts
  
$
 316 
  
$
 66 
  
$
 821 
  
$
 (618)
  
$
 (88)

 
194
 
 
Amount of Gain (Loss) Recognized on
 
Risk Management Contracts
 
For the Six Months Ended June 30, 2013
   
 
Location of Gain (Loss)
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
         
(in thousands)
 
Electric Generation, Transmission and
                              
   
Distribution Revenues
  
$
 873 
  
$
 7,844 
  
$
 3,533 
  
$
 216 
  
$
 330 
 
Sales to AEP Affiliates
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
 
Fuel and Other Consumables Used for
                              
   
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
 
Regulatory Assets (a)
    
 - 
    
 (1,099)
    
 (5,697)
    
 2,202 
    
 (102)
 
Regulatory Liabilities (a)
    
 (210)
    
 (6,062)
    
 3,360 
    
 - 
    
 135 
 
Total Gain (Loss) on Risk Management
                              
   
Contracts
  
$
 663 
  
$
 683 
  
$
 1,196 
  
$
 2,418 
  
$
 363 
                                     
 
Amount of Gain (Loss) Recognized on
 
Risk Management Contracts
 
For the Six Months Ended June 30, 2012
   
 
Location of Gain (Loss)
  
APCo
  
I&M
  
OPCo
  
PSO
  
SWEPCo
         
(in thousands)
 
Electric Generation, Transmission and
                              
   
Distribution Revenues
  
$
 (926)
  
$
 5,392 
  
$
 11,031 
  
$
 160 
  
$
 252 
 
Sales to AEP Affiliates
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
 
Fuel and Other Consumables Used for
                              
   
Electric Generation
    
 - 
    
 - 
    
 - 
    
 - 
    
 - 
 
Regulatory Assets (a)
    
 (7,277)
    
 (6,015)
    
 (12,026)
    
 (5,958)
    
 (7,092)
 
Regulatory Liabilities (a)
    
 11,120 
    
 7,118 
    
 7,178 
    
 1 
    
 (5)
 
Total Gain (Loss) on Risk Management
                              
   
Contracts
  
$
 2,917 
  
$
 6,495 
  
$
 6,183 
  
$
 (5,797)
  
$
 (6,845)
                                     
 
(a)   Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current
 
        or noncurrent on the condensed balance sheets.

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

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

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes.  Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances.  However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
 
195
 

Accounting for Fair Value Hedging Strategies

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

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income.  During the three and six months ended June 30, 2013 and 2012, the Registrant Subsidiaries did not designate any fair value hedging strategies.

Accounting for Cash Flow Hedging Strategies

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

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

The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income.  During the three and six months ended June 30, 2013 and 2012, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur.  During the three and six months ended June 30, 2013, I&M designated interest rate derivatives as cash flow hedges.  During the three and six months ended June 30, 2012, I&M and SWEPCo designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.  During the three and six months ended June 30, 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges.  During the three and six months ended June 30, 2012, SWEPCo designated foreign currency derivatives as cash flow hedges.

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

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2013 and 2012, see Note 2.

 
196
 


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

 
Impact of Cash Flow Hedges on the Registrant Subsidiaries’
 
Condensed Balance Sheets
 
June 30, 2013
   
       
Hedging Assets (a)
  
Hedging Liabilities (a)
  
AOCI Gain (Loss) Net of Tax
           
Interest Rate
      
Interest Rate
      
Interest Rate
           
and Foreign
      
and Foreign
      
and Foreign
 
Company
  
Commodity
  
Currency
  
Commodity
  
Currency
  
Commodity
  
Currency
       
(in thousands)
 
APCo
  
$
 570 
  
$
 - 
  
$
 278 
  
$
 - 
  
$
 197 
  
$
 2,583 
 
I&M
    
 393 
    
 - 
    
 174 
    
 - 
    
 147 
    
 (16,796)
 
OPCo
    
 805 
    
 - 
    
 371 
    
 - 
    
 289 
    
 7,415 
 
PSO
    
 2 
    
 - 
    
 45 
    
 - 
    
 (21)
    
 6,081 
 
SWEPCo
    
 2 
    
 - 
    
 56 
    
 - 
    
 (26)
    
 (14,437)

     
Expected to be Reclassified to
      
     
Net Income During the Next
      
     
Twelve Months
      
             
Maximum Term for
         
Interest Rate
  
Exposure to
         
and Foreign
  
Variability of Future
Company
  
Commodity
  
Currency
  
Cash Flows
     
(in thousands)
  
(in months)
APCo
  
$
 213 
  
$
 (1,013)
    
 18 
I&M
    
 153 
    
 (1,640)
    
 18 
OPCo
    
 308 
    
 1,359 
    
 18 
PSO
    
 (13)
    
 759 
    
 18 
SWEPCo
    
 (17)
    
 (2,267)
    
 18 

 
Impact of Cash Flow Hedges on the Registrant Subsidiaries’
 
Condensed Balance Sheets
 
December 31, 2012
   
       
Hedging Assets (a)
  
Hedging Liabilities (a)
  
AOCI Gain (Loss) Net of Tax
           
Interest Rate
      
Interest Rate
      
Interest Rate
           
and Foreign
      
and Foreign
      
and Foreign
 
Company
  
Commodity
  
Currency
  
Commodity
  
Currency
  
Commodity
  
Currency
       
(in thousands)
 
APCo
  
$
 302 
  
$
 - 
  
$
 1,355 
  
$
 - 
  
$
 (644)
  
$
 2,077 
 
I&M
    
 200 
    
 - 
    
 931 
    
 19,524 
    
 (446)
    
 (19,647)
 
OPCo
    
 416 
    
 - 
    
 1,903 
    
 - 
    
 (912)
    
 8,095 
 
PSO
    
 25 
    
 - 
    
 - 
    
 - 
    
 21 
    
 6,460 
 
SWEPCo
    
 24 
    
 - 
    
 - 
    
 - 
    
 22 
    
 (15,571)

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

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

 
197
 
The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

Credit Risk

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

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

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade.  The amount of collateral required fluctuates based on market prices and total exposure.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts.  The Registrant Subsidiaries have not experienced a downgrade below investment grade.  The following tables represent: (a) the Registrant Subsidiaries’ fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of June 30, 2013 and December 31, 2012:

       
June 30, 2013
       
Liabilities for
  
Amount of Collateral the
  
Amount
       
Derivative Contracts
  
Registrant Subsidiaries
  
Attributable to
       
with Credit
  
Would Have Been
  
RTO and ISO
 
Company
  
Downgrade Triggers
  
Required to Post
  
Activities
       
(in thousands)
 
APCo
  
$
 937 
  
$
 6,147 
  
$
 6,074 
 
I&M
    
 647 
    
 4,248 
    
 4,197 
 
OPCo
    
 1,324 
    
 8,692 
    
 8,588 
 
PSO
    
 - 
    
 1,533 
    
 1,306 
 
SWEPCo
    
 - 
    
 1,810 
    
 1,542 

       
December 31, 2012
       
Liabilities for
  
Amount of Collateral the
  
Amount
       
Derivative Contracts
  
Registrant Subsidiaries
  
Attributable to
       
with Credit
  
Would Have Been
  
RTO and ISO
 
Company
  
Downgrade Triggers
  
Required to Post
  
Activities
       
(in thousands)
 
APCo
  
$
 2,159 
  
$
 3,699 
  
$
 3,510 
 
I&M
    
 1,483 
    
 2,540 
    
 2,411 
 
OPCo
    
 3,034 
    
 5,198 
    
 4,933 
 
PSO
    
 - 
    
 1,509 
    
 1,429 
 
SWEPCo
    
 - 
    
 1,778 
    
 1,683 

 
198
 
In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts.  The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of June 30, 2013 and December 31, 2012:

     
June 30, 2013
     
Liabilities for
      
Additional
     
Contracts with Cross
      
Settlement
     
Default Provisions
      
Liability if Cross
     
Prior to Contractual
  
Amount of Cash
  
Default Provision
Company
  
Netting Arrangements
  
Collateral Posted
  
is Triggered
     
(in thousands)
APCo
  
$
 31,949 
  
$
 - 
  
$
 24,748 
I&M
    
 22,079 
    
 - 
    
 17,102 
OPCo
    
 45,175 
    
 - 
    
 34,993 
PSO
    
 15 
    
 - 
    
 14 
SWEPCo
    
 18 
    
 - 
    
 17 
                     
     
December 31, 2012
     
Liabilities for
      
Additional
     
Contracts with Cross
      
Settlement
     
Default Provisions
      
Liability if Cross
     
Prior to Contractual
  
Amount of Cash
  
Default Provision
Company
  
Netting Arrangements
  
Collateral Posted
  
is Triggered
     
(in thousands)
APCo
  
$
 49,465 
  
$
 1,822 
  
$
 30,160 
I&M
    
 53,499 
    
 1,252 
    
 40,240 
OPCo
    
 69,516 
    
 2,561 
    
 42,386 
PSO
    
 - 
    
 - 
    
 - 
SWEPCo
    
 - 
    
 - 
    
 - 

9.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.  The AEP System’s market risk oversight staff independently monitors its valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures.  The CORC consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer.
 
199
 

For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, the quoted bid and ask prices are averaged.  In certain circumstances, a broker quote may be discarded if it is a clear outlier.  Management uses a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs.  Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.  The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market.  A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts.  AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value.  AEP’s management performs its own valuation testing to verify the fair values of the securities.  AEP receives audit reports of the trustee’s operating controls and valuation processes.  The trustee uses multiple pricing vendors for the assets held in the trusts.

Assets in the nuclear trusts, Other Cash Deposits and Cash and Cash Equivalents are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds.  Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

Fair Value Measurements of Long-term Debt

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of June 30, 2013 and December 31, 2012 are summarized in the following table:

   
June 30, 2013
  
December 31, 2012
Company
  
Book Value
  
Fair Value
  
Book Value
  
Fair Value
   
(in thousands)
APCo
  
$
 3,702,759 
  
$
 4,241,900 
  
$
 3,702,442 
  
$
 4,555,143 
I&M
    
 2,305,192 
    
 2,490,561 
    
 2,057,666 
    
 2,372,017 
OPCo
    
 3,504,794 
    
 4,002,270 
    
 3,860,440 
    
 4,560,337 
PSO
    
 949,841 
    
 1,107,094 
    
 949,871 
    
 1,175,759 
SWEPCo
    
 2,044,780 
    
 2,231,426 
    
 2,046,228 
    
 2,400,509 

 
200
 
Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

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

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

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

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

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

       
June 30, 2013
  
December 31, 2012
       
Estimated
  
Gross
  
Other-Than-
  
Estimated
  
Gross
  
Other-Than-
     
Fair
Unrealized
Temporary
Fair
Unrealized
Temporary
     
Value
Gains (Losses)
Impairments
Value
Gains
Impairments
       
(in thousands)
 
Cash and Cash Equivalents
  
$
 14,132 
  
$
 - 
  
$
 - 
  
$
 16,783 
  
$
 - 
  
$
 - 
 
Fixed Income Securities:
                                    
   
United States Government
    
 604,850 
    
 37,609 
    
 (2,085)
    
 647,918 
    
 58,268 
    
 (747)
   
Corporate Debt
    
 35,202 
    
 2,963 
    
 (1,592)
    
 35,399 
    
 4,903 
    
 (1,352)
   
State and Local Government
    
 262,521 
    
 (1,661)
    
 (2,832)
    
 270,090 
    
 1,006 
    
 (863)
   
  Subtotal Fixed Income Securities
  
 902,573 
    
 38,911 
    
 (6,509)
    
 953,407 
    
 64,177 
    
 (2,962)
 
Equity Securities - Domestic
    
 874,689 
    
 372,591 
    
 (82,148)
    
 735,582 
    
 284,599 
    
 (76,557)
 
Spent Nuclear Fuel and
                                    
   
Decommissioning Trusts
  
$
 1,791,394 
  
$
 411,502 
  
$
 (88,657)
  
$
 1,705,772 
  
$
 348,776 
  
$
 (79,519)

 
201
 
The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2013 and 2012:

   
Three Months Ended June 30,
  
Six Months Ended June 30,
   
2013 
  
2012 
  
2013 
  
2012 
   
(in thousands)
 
Proceeds from Investment Sales
$
 218,272 
  
$
 182,179 
  
$
 385,942 
  
$
 516,579 
 
Purchases of Investments
  
 227,470 
    
 192,104 
    
 411,769 
    
 544,981 
 
Gross Realized Gains on Investment Sales
  
 8,575 
    
 3,380 
    
 11,898 
    
 4,932 
 
Gross Realized Losses on Investment Sales
  
 7,397 
    
 803 
    
 9,712 
    
 2,219 

The adjusted cost of fixed income securities was $862 million and $889 million as of June 30, 2013 and December 31, 2012, respectively.  The adjusted cost of equity securities was $502 million and $451 million as of June 30, 2013 and December 31, 2012, respectively.

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

 
Fair Value of
 
Fixed Income
 
Securities
 
(in thousands)
Within 1 year
$
 78,832 
1 year – 5 years
  
 340,397 
5 years – 10 years
  
 238,064 
After 10 years
  
 245,280 
Total
$
 902,573 

 
202
 
Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2013 and December 31, 2012.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in management’s valuation techniques.

APCo
                            
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2013
                     
   
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in thousands)
                               
Risk Management Assets
                            
Risk Management Commodity Contracts (a) (b)
$
 2,555 
  
$
 107,096 
  
$
 15,526 
  
$
 (73,619)
  
$
 51,558 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 995 
    
 - 
    
 (425)
    
 570 
Total Risk Management Assets
$
 2,555 
  
$
 108,091 
  
$
 15,526 
  
$
 (74,044)
  
$
 52,128 
                               
Liabilities:
                            
                               
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (b)
$
 1,477 
  
$
 101,183 
  
$
 2,550 
  
$
 (78,084)
  
$
 27,126 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 703 
    
 - 
    
 (425)
    
 278 
Total Risk Management Liabilities
$
 1,477 
  
$
 101,886 
  
$
 2,550 
  
$
 (78,509)
  
$
 27,404 

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

 
203
 


I&M
                            
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2013
                       
     
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in thousands)
                                 
Risk Management Assets
                            
Risk Management Commodity Contracts (a) (b)
$
 1,766 
  
$
 73,702 
  
$
 10,729 
  
$
 (50,676)
  
$
 35,521 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 686 
    
 - 
    
 (293)
    
 393 
Total Risk Management Assets
  
 1,766 
    
 74,388 
    
 10,729 
    
 (50,969)
    
 35,914 
                                 
Spent Nuclear Fuel and Decommissioning Trusts
                            
Cash and Cash Equivalents (c)
  
 2,939 
    
 - 
    
 - 
    
 11,193 
    
 14,132 
Fixed Income Securities:
                            
 
United States Government
  
 - 
    
 604,850 
    
 - 
    
 - 
    
 604,850 
 
Corporate Debt
  
 - 
    
 35,202 
    
 - 
    
 - 
    
 35,202 
 
State and Local Government
  
 - 
    
 262,521 
    
 - 
    
 - 
    
 262,521 
   
Subtotal Fixed Income Securities
  
 - 
    
 902,573 
    
 - 
    
 - 
    
 902,573 
Equity Securities - Domestic (d)
  
 874,689 
    
 - 
    
 - 
    
 - 
    
 874,689 
Total Spent Nuclear Fuel and Decommissioning Trusts
  
 877,628 
    
 902,573 
    
 - 
    
 11,193 
    
 1,791,394 
                                 
Total Assets
$
 879,394 
  
$
 976,961 
  
$
 10,729 
  
$
 (39,776)
  
$
 1,827,308 
                                 
Liabilities:
                            
                                 
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (b)
$
 1,021 
  
$
 70,200 
  
$
 1,762 
  
$
 (53,750)
  
$
 19,233 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 467 
    
 - 
    
 (293)
    
 174 
Total Risk Management Liabilities
$
 1,021 
  
$
 70,667 
  
$
 1,762 
  
$
 (54,043)
  
$
 19,407 

 
204
 


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

 
205
 


OPCo
                            
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
June 30, 2013
                               
   
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in thousands)
                               
Other Cash Deposits (e)
$
 - 
  
$
 26 
  
$
 - 
  
$
 39 
  
$
 65 
                               
Risk Management Assets
                            
Risk Management Commodity Contracts (a) (b)
  
 3,613 
    
 155,550 
    
 21,953 
    
 (107,395)
    
 73,721 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 1,405 
    
 - 
    
 (600)
    
 805 
Total Risk Management Assets
  
 3,613 
    
 156,955 
    
 21,953 
    
 (107,995)
    
 74,526 
                               
Total Assets
$
 3,613 
  
$
 156,981 
  
$
 21,953 
  
$
 (107,956)
  
$
 74,591 
                               
Liabilities:
                            
                               
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (b)
$
 2,088 
  
$
 147,199 
  
$
 3,606 
  
$
 (113,692)
  
$
 39,201 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 971 
    
 - 
    
 (600)
    
 371 
Total Risk Management Liabilities
$
 2,088 
  
$
 148,170 
  
$
 3,606 
  
$
 (114,292)
  
$
 39,572 

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

 
206
 


PSO
                            
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
June 30, 2013
                     
   
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in thousands)
                               
Risk Management Assets
                            
Risk Management Commodity Contracts (a) (b)
$
 - 
  
$
 1,289 
  
$
 - 
  
$
 (807)
  
$
 482 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 6 
    
 - 
    
 (4)
    
 2 
Total Risk Management Assets
$
 - 
  
$
 1,295 
  
$
 - 
  
$
 (811)
  
$
 484 
                               
Liabilities:
                            
                               
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (b)
$
 - 
  
$
 2,910 
  
$
 - 
  
$
 (842)
  
$
 2,068 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 49 
    
 - 
    
 (4)
    
 45 
Total Risk Management Liabilities
$
 - 
  
$
 2,959 
  
$
 - 
  
$
 (846)
  
$
 2,113 

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

 
207
 


SWEPCo
                            
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2013
                   
   
Level 1
  
Level 2
  
Level 3
  
Other
  
Total
Assets:
(in thousands)
                               
Cash and Cash Equivalents (e)
$
 10,078 
  
$
 - 
  
$
 - 
  
$
 1,762 
  
$
 11,840 
                               
Risk Management Assets
                            
Risk Management Commodity Contracts (a) (b)
  
 - 
    
 1,846 
    
 - 
    
 (1,450)
    
 396 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 7 
    
 - 
    
 (5)
    
 2 
Total Risk Management Assets
  
 - 
    
 1,853 
    
 - 
    
 (1,455)
    
 398 
                               
Total Assets
$
 10,078 
  
$
 1,853 
  
$
 - 
  
$
 307 
  
$
 12,238 
                               
Liabilities:
                            
                               
Risk Management Liabilities
                            
Risk Management Commodity Contracts (a) (b)
$
 - 
  
$
 2,382 
  
$
 - 
  
$
 (1,494)
  
$
 888 
Cash Flow Hedges:
                            
 
Commodity Hedges (a)
  
 - 
    
 61 
    
 - 
    
 (5)
    
 56 
Total Risk Management Liabilities
$
 - 
  
$
 2,443 
  
$
 - 
  
$
 (1,499)
  
$
 944 

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

(a)
Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
(b)
Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
(c)
Amounts in “Other” column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(d)
Amounts represent publicly traded equity securities and equity-based mutual funds.
(e)
Amounts in “Other” column primarily represent cash deposits with third parties.  Level 1 and Level 2 amounts primarily represent investments in money market funds.

There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2013 and 2012.
 
 
208
 

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

Three Months Ended June 30, 2013
  
APCo
  
I&M
  
OPCo
   
(in thousands)
Balance as of March 31, 2013
  
$
 8,756 
  
$
 6,051 
  
$
 12,381 
Realized Gain (Loss) Included in Net Income
                  
 
(or Changes in Net Assets) (a) (b)
    
 (369)
    
 (255)
    
 (522)
Unrealized Gain (Loss) Included in Net
                  
 
Income (or Changes in Net Assets) Relating
                  
 
to Assets Still Held at the Reporting Date (a)
    
 - 
    
 - 
    
 2,390 
Realized and Unrealized Gains (Losses)
                  
 
Included in Other Comprehensive Income
    
 - 
    
 - 
    
 - 
Purchases, Issuances and Settlements (c)
    
 641 
    
 443 
    
 906 
Transfers into Level 3 (d) (e)
    
 243 
    
 168 
    
 344 
Transfers out of Level 3 (e) (f)
    
 (362)
    
 (250)
    
 (512)
Changes in Fair Value Allocated to Regulated
                  
 
Jurisdictions (g)
    
 4,067 
    
 2,810 
    
 3,360 
Balance as of June 30, 2013
  
$
 12,976 
  
$
 8,967 
  
$
 18,347 

Three Months Ended June 30, 2012
  
APCo
  
I&M
  
OPCo
   
(in thousands)
Balance as of March 31, 2012
  
$
 7,981 
  
$
 5,614 
  
$
 11,767 
Realized Gain (Loss) Included in Net Income
                  
 
(or Changes in Net Assets) (a) (b)
    
 (3,210)
    
 (2,258)
    
 (4,734)
Unrealized Gain (Loss) Included in Net
                  
 
Income (or Changes in Net Assets) Relating
                  
 
to Assets Still Held at the Reporting Date (a)
    
 - 
    
 - 
    
 1,711 
Realized and Unrealized Gains (Losses)
                  
 
Included in Other Comprehensive Income
    
 (11)
    
 (8)
    
 (16)
Purchases, Issuances and Settlements (c)
    
 4,988 
    
 3,508 
    
 7,355 
Transfers into Level 3 (d) (e)
    
 1,301 
    
 915 
    
 1,919 
Transfers out of Level 3 (e) (f)
    
 (557)
    
 (392)
    
 (821)
Changes in Fair Value Allocated to Regulated
                  
 
Jurisdictions (g)
    
 2,372 
    
 1,670 
    
 1,788 
Balance as of June 30, 2012
  
$
 12,864 
  
$
 9,049 
  
$
 18,969 

 
209
 
Six Months Ended June 30, 2013
  
APCo
  
I&M
  
OPCo
   
(in thousands)
Balance as of December 31, 2012
  
$
 10,979 
  
$
 7,541 
  
$
 15,429 
Realized Gain (Loss) Included in Net Income
                  
 
(or Changes in Net Assets) (a) (b)
    
 (3,532)
    
 (2,439)
    
 (4,990)
Unrealized Gain (Loss) Included in Net
                  
 
Income (or Changes in Net Assets) Relating
                  
 
to Assets Still Held at the Reporting Date (a)
    
 - 
    
 - 
    
 598 
Realized and Unrealized Gains (Losses)
                  
 
Included in Other Comprehensive Income
    
 - 
    
 - 
    
 - 
Purchases, Issuances and Settlements (c)
    
 2,859 
    
 1,977 
    
 4,045 
Transfers into Level 3 (d) (e)
    
 875 
    
 602 
    
 1,231 
Transfers out of Level 3 (e) (f)
    
 (941)
    
 (648)
    
 (1,326)
Changes in Fair Value Allocated to Regulated
                  
 
Jurisdictions (g)
    
 2,736 
    
 1,934 
    
 3,360 
Balance as of June 30, 2013
  
$
 12,976 
  
$
 8,967 
  
$
 18,347 

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

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

 
210
 
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of June 30, 2013:

 
APCo
                                
     
Fair Value
  
Valuation
  
Significant
  
Forward Price Range
   
Assets
  
Liabilities
Technique
Unobservable Input (a)
  
Low
  
High
     
(in thousands)
                    
 
Energy Contracts
  
$
 11,823 
  
$
 1,613 
  
Discounted Cash Flow
  
Forward Market Price
  
$
 11.48 
  
$
 70.90 
 
FTRs
    
 3,703 
    
 937 
  
Discounted Cash Flow
  
Forward Market Price
    
 (12.31)
    
 11.19 
 
Total
  
$
 15,526 
  
$
 2,550 
                    

 
I&M
                                
     
Fair Value
  
Valuation
  
Significant
  
Forward Price Range
   
Assets
  
Liabilities
Technique
Unobservable Input (a)
  
Low
  
High
     
(in thousands)
                    
 
Energy Contracts
  
$
 8,170 
  
$
 1,115 
  
Discounted Cash Flow
  
Forward Market Price
  
$
 11.48 
  
$
 70.90 
 
FTRs
    
 2,559 
    
 647 
  
Discounted Cash Flow
  
Forward Market Price
    
 (12.31)
    
 11.19 
 
Total
  
$
 10,729 
  
$
 1,762 
                    

 
OPCo
                                
     
Fair Value
  
Valuation
  
Significant
  
Forward Price Range
   
Assets
  
Liabilities
Technique
Unobservable Input (a)
  
Low
  
High
     
(in thousands)
                    
 
Energy Contracts
  
$
 16,717 
  
$
 2,282 
  
Discounted Cash Flow
  
Forward Market Price
  
$
 11.48 
  
$
 70.90 
 
FTRs
    
 5,236 
    
 1,324 
  
Discounted Cash Flow
  
Forward Market Price
    
 (12.31)
    
 11.19 
 
Total
  
$
 21,953 
  
$
 3,606 
                    

 
(a)
Represents market prices in dollars per MWh.

10.  INCOME TAXES

AEP System Tax Allocation Agreement

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

Federal and State Income Tax Audit Status

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

The Registrant Subsidiaries file income tax returns in various state and local jurisdictions.  These taxing authorities routinely examine the tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions.  Management believes that previously filed tax returns have positions that may be challenged by these tax authorities.  However, management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income.  The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2008.
 
211
 

11.  FINANCING ACTIVITIES

Long-term Debt

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

         
Principal
  
Interest
    
 
Company
  
Type of Debt
  
Amount (a)
  
Rate
  
Due Date
 
Issuances:
      
(in thousands)
  
(%)
    
 
I&M
  
Notes Payable
  
$
 101,354 
  
Variable
  
2017 
 
I&M
  
Senior Unsecured Notes
    
 250,000 
  
3.20 
  
2023 
 
OPCo
  
Long-term Debt - Affiliated
    
 200,000 
(b)
Variable
  
2015 
 
OPCo
  
Pollution Control Bonds
    
 50,000 
  
Variable
  
2014 

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

           
Principal
  
Interest
    
 
Company
  
Type of Debt
  
Amount Paid
  
Rate
  
Due Date
 
Retirements and
      
(in thousands)
  
(%)
    
   
Principal Payments:
                  
 
APCo
  
Land Note
  
$
 14 
  
13.718 
  
2026 
 
I&M
  
Notes Payable
    
 6,083 
  
5.44 
  
2013 
 
I&M
  
Notes Payable
    
 9,811 
  
4.00 
  
2014 
 
I&M
  
Notes Payable
    
 8,054 
  
Variable
  
2015 
 
I&M
  
Notes Payable
    
 9,731 
  
Variable
  
2016 
 
I&M
  
Notes Payable
    
 6,739 
  
2.12 
  
2016 
 
I&M
  
Notes Payable
    
 20,859 
  
Variable
  
2016 
 
I&M
  
Other Long-term Debt
    
 454 
  
6.00 
  
2025 
 
I&M
  
Other Long-term Debt
    
 2,062 
  
Variable
  
2015 
 
I&M
  
Pollution Control Bonds
    
 40,000 
  
5.25 
  
2025 
 
OPCo
  
Pollution Control Bonds
    
 56,000 
  
5.10 
  
2013 
 
OPCo
  
Pollution Control Bonds
    
 50,000 
  
5.15 
  
2026 
 
OPCo
  
Senior Unsecured Notes
    
 250,000 
  
5.50 
  
2013 
 
OPCo
  
Senior Unsecured Notes
    
 250,000 
  
5.50 
  
2013 
 
PSO
  
Notes Payable
    
 200 
  
3.00 
  
2027 
 
SWEPCo
  
Notes Payable
    
 1,625 
  
4.58 
  
2032 

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

In July 2013, I&M retired $12 million of Notes Payable related to DCC Fuel.
 
In July 2013, OPCo retired $65 million of 4.9% Pollution Control Bonds due in 2037 and issued $65 million of variable rate Pollution Control Bonds due in 2014.

As of June 30, 2013, trustees held on behalf of I&M and OPCo, $40 million and $464 million, respectively, of their reacquired Pollution Control Bonds.
 
212
 

Dividend Restrictions

The Registrant Subsidiaries pay dividends to Parent provided funds are legally available.  Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

Federal Power Act

The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.”  The term “capital account” is not defined in the Federal Power Act or its regulations.  Management understands “capital account” to mean the book value of the common stock.

Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants.  Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo.

None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

Leverage Restrictions

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

Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds AEP’s majority of the nonutility subsidiaries.  The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC.  The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of June 30, 2013 and December 31, 2012 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ condensed balance sheets.  The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the six months ended June 30, 2013 are described in the following table:

                             
Net
      
                             
Loans to
      
     
Maximum
  
Maximum
  
Average
  
Average
  
(Borrowings from)
  
Authorized
     
Borrowings
  
Loans
  
Borrowings
  
Loans
  
the Utility
  
Short-term
     
from the Utility
  
to the Utility
  
from the Utility
  
to the Utility
  
Money Pool as of
  
Borrowing
 
Company
  
Money Pool
  
Money Pool
  
Money Pool
  
Money Pool
  
June 30, 2013
  
Limit
     
(in thousands)
 
APCo
  
$
 217,174 
  
$
 23,871 
  
$
 100,093 
  
$
 23,478 
  
$
 (64,480)
  
$
 600,000 
 
I&M
    
 23,135 
    
 355,659 
    
 8,308 
    
 198,197 
    
 273,117 
    
 500,000 
 
OPCo
    
 410,456 
    
 169,284 
    
 241,993 
    
 31,664 
    
 (281,672)
    
 600,000 
 
PSO
    
 46,806 
    
 25,343 
    
 20,136 
    
 11,603 
    
 (25,276)
    
 300,000 
 
SWEPCo
    
 15,386 
    
 153,830 
    
 4,473 
    
 49,757 
    
 14,806 
    
 350,000 

 
213
 
The activity in the above table does not include short-term lending activity of OPCo’s wholly-owned subsidiary, AEPGenCo, which is a participant in the Nonutility Money Pool.  The amounts of outstanding borrowings from the Nonutility Money Pool as of June 30, 2013 is included in Advances to Affiliates on OPCo’s condensed balance sheet.  For the six months ended June 30, 2013, AEPGenCo had the following activity in the Nonutility Money Pool:

                       
Maximum
  
Maximum
  
Average
  
Average
  
Borrowings
  
Borrowings
  
Loans
  
Borrowings
  
Loans
  
from the Nonutility
  
from the Nonutility
  
to the Nonutility
  
from the Nonutility
  
to the Nonutility
  
Money Pool as of
  
Money Pool
  
Money Pool
  
Money Pool
  
Money Pool
  
June 30, 2013
  
(in thousands)
$
 1,047 
  
$
 1,027 
  
$
 115 
  
$
 208 
  
$
 58 
  

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

   
Six Months Ended June 30,
   
2013 
  
2012 
Maximum Interest Rate
  
 0.43 
%
  
 0.56 
%
Minimum Interest Rate
  
 0.32 
%
  
 0.45 
%

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

   
Average Interest Rate
  
Average Interest Rate
   
for Funds Borrowed
  
 for Funds Loaned
   
from the Utility Money Pool for
  
 to the Utility Money Pool for
   
Six Months Ended June 30,
  
Six Months Ended June 30,
Company
  
2013 
  
2012 
2013 
  
2012 
APCo
  
 0.36 
%
  
 0.49 
%
  
 0.36 
%
  
 0.49 
%
I&M
  
 0.36 
%
  
 - 
%
  
 0.35 
%
  
 0.49 
%
OPCo
  
 0.35 
%
  
 0.47 
%
  
 0.37 
%
  
 0.51 
%
PSO
  
 0.34 
%
  
 - 
%
  
 0.38 
%
  
 0.48 
%
SWEPCo
  
 0.34 
%
  
 0.53 
%
  
 0.37 
%
  
 0.48 
%

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

   
Maximum
  
Minimum
  
Maximum
  
Minimum
  
Average
  
Average
   
Interest Rate
  
Interest Rate
  
Interest Rate
  
Interest Rate
  
Interest Rate
  
Interest Rate
   
for Funds
  
for Funds
  
for Funds
  
for Funds
  
for Funds
  
for Funds
Six Months
  
Borrowed from
  
Borrowed from
  
Loaned to
  
Loaned to
  
Borrowed from
  
Loaned to
Ended
  
the Nonutility
  
the Nonutility
  
the Nonutility
  
the Nonutility
  
the Nonutility
  
the Nonutility
June 30,
  
Money Pool
  
Money Pool
Money Pool
  
Money Pool
  
Money Pool
  
Money Pool
2013 
  
 0.61 
%
  
 0.57 
%
  
 0.35 
%
  
 0.32 
%
  
 0.61 
%
  
 0.34 
%

Short-term Debt
                        
                                 
The Registrant Subsidiaries’ outstanding short-term debt was as follows:
                                 
           
June 30, 2013
  
December 31, 2012
           
Outstanding
  
Interest
  
Outstanding
  
Interest
 
Company
  
Type of Debt
Amount
Rate (a)
  
Amount
Rate (a)
           
(in thousands)
        
(in thousands)
      
 
SWEPCo
  
Line of Credit – Sabine
  
$
 - 
  
 - 
%
  
$
 2,603 
  
 1.82 
%

(a)  Weighted average rate.

 
214
 
Credit Facilities

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

Sale of Receivables – AEP Credit

Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables.  APCo does not have regulatory authority to sell its West Virginia accounts receivable.  The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ condensed statements of income.  The Registrant Subsidiaries manage and service their customer accounts receivable sold.

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

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of June 30, 2013 and December 31, 2012 was as follows:

     
June 30,
  
December 31,
Company
  
2013 
  
2012 
     
(in thousands)
APCo
  
$
 146,352 
  
$
 153,719 
I&M
    
 139,932 
    
 123,447 
OPCo
    
 339,389 
    
 300,675 
PSO
    
 127,497 
    
 85,530 
SWEPCo
    
 166,278 
    
 132,449 

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

     
Three Months Ended June 30,
  
Six Months Ended June 30,
Company
  
2013 
  
2012 
  
2013 
  
2012 
     
(in thousands)
APCo
  
$
 1,459 
  
$
 1,556 
  
$
 3,015 
  
$
 3,686 
I&M
    
 1,530 
    
 1,521 
    
 2,982 
    
 3,064 
OPCo
    
 4,695 
    
 4,622 
    
 9,364 
    
 10,538 
PSO
    
 1,351 
    
 1,825 
    
 2,765 
    
 3,557 
SWEPCo
    
 1,384 
    
 1,548 
    
 2,764 
    
 2,934 

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

     
Three Months Ended June 30,
  
Six Months Ended June 30,
Company
  
2013 
  
2012 
  
2013 
  
2012 
     
(in thousands)
APCo
  
$
 342,984 
  
$
 295,879 
  
$
 741,177 
  
$
 642,405 
I&M
    
 361,417 
    
 320,415 
    
 713,247 
    
 659,996 
OPCo
    
 661,959 
    
 656,737 
    
 1,358,917 
    
 1,494,634 
PSO
    
 321,620 
    
 303,729 
    
 561,895 
    
 576,524 
SWEPCo
    
 389,076 
    
 379,114 
    
 721,012 
    
 700,722 

 
215
 
12.  VARIABLE INTEREST ENTITIES

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE.  A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.  Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.”  In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors.  Management believes that significant assumptions and judgments were applied consistently.  In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.

SWEPCo is the primary beneficiary of Sabine.  I&M is the primary beneficiary of DCC Fuel.  SWEPCo holds a significant variable interest in DHLC.  Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC.  I&M and OPCo each hold a significant variable interest in AEGCo.
 
Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the three months ended June 30, 2013 and 2012 were $40 million and $36 million, respectively, and for the six months ended June 30, 2013 and 2012 were $84 million and $91 million, respectively.  See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets.

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

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
June 30, 2013 and December 31, 2012
(in thousands)
   
Sabine
ASSETS
  
2013 
  
2012 
Current Assets
  
$
 65,744 
  
$
 56,535 
Net Property, Plant and Equipment
    
 163,078 
    
 170,436 
Other Noncurrent Assets
    
 65,952 
    
 55,076 
Total Assets
  
$
 294,774 
  
$
 282,047 
             
LIABILITIES AND EQUITY
            
Current Liabilities
  
$
 30,854 
  
$
 31,446 
Noncurrent Liabilities
    
 263,553 
    
 250,340 
Equity
    
 367 
    
 261 
Total Liabilities and Equity
  
$
 294,774 
  
$
 282,047 

I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI LLC (collectively DCC Fuel).  DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the leases for the three months ended June 30, 2013 and 2012 were $38 million and $42 million, respectively, and for the six months ended June 30, 2013 and 2012 were $64 million and $59 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to
 
 
216
 
the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months.  Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s condensed balance sheets.

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

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
June 30, 2013 and December 31, 2012
(in thousands)
   
DCC Fuel
ASSETS
  
2013 
  
2012 
Current Assets
  
$
 161,377 
  
$
 132,886 
Net Property, Plant and Equipment
    
 219,101 
    
 176,065 
Other Noncurrent Assets
    
 104,035 
    
 92,473 
Total Assets
  
$
 484,513 
  
$
 401,424 
             
LIABILITIES AND EQUITY
            
Current Liabilities
  
$
 142,829 
  
$
 120,873 
Noncurrent Liabilities
    
 341,684 
    
 280,551 
Equity
    
 - 
    
 - 
Total Liabilities and Equity
  
$
 484,513 
  
$
 401,424 

DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and voting rights equally.  Each entity guarantees 50% of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  SWEPCo’s total billings from DHLC for the three months ended June 30, 2013 and 2012 were $13 million and $20 million, respectively, and for the six months ended June 30, 2013 and 2012 were $31 million and $34 million, respectively.  SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC.  SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheets.

SWEPCo’s investment in DHLC was:

     
June 30, 2013
  
December 31, 2012
     
As Reported on
  
Maximum
  
As Reported on
  
Maximum
     
the Balance Sheet
Exposure
the Balance Sheet
  
Exposure
     
(in thousands)
 
Capital Contribution from SWEPCo
  
$
 7,643 
  
$
 7,643 
  
$
 7,643 
  
$
 7,643 
 
Retained Earnings
    
 974 
    
 974 
    
 946 
    
 946 
 
SWEPCo's Guarantee of Debt
    
 - 
    
 49,600 
    
 - 
    
 49,564 
                           
 
Total Investment in DHLC
  
$
 8,617 
  
$
 58,217 
  
$
 8,589 
  
$
 58,153 

AEPSC provides certain managerial and professional services to AEP’s subsidiaries.  AEP is the sole equity owner of AEPSC.  AEP management controls the activities of AEPSC.  The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost.  AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered.  AEPSC finances its operations through cost reimbursement from other AEP subsidiaries.  There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business.  AEPSC and its billings are subject to regulation by the FERC.  AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations.  AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure.  However, AEP subsidiaries do not have control over AEPSC.  AEPSC is consolidated by AEP.  In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.
 
217
 

Total AEPSC billings to the Registrant Subsidiaries were as follows:

                         
   
Three Months Ended June 30,
  
Six Months Ended June 30,
Company
  
2013 
  
2012 
  
2013 
  
2012 
   
(in thousands)
APCo
  
$
 41,496 
  
$
 43,894 
  
$
 80,537 
  
$
 82,440 
I&M
    
 28,706 
    
 31,377 
    
 56,204 
    
 57,484 
OPCo
    
 57,351 
    
 67,490 
    
 111,420 
    
 120,935 
PSO
    
 19,807 
    
 21,301 
    
 37,969 
    
 38,897 
SWEPCo
    
 29,595 
    
 33,246 
    
 57,075 
    
 59,966 

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

                         
   
June 30, 2013
  
December 31, 2012
   
As Reported on the
  
Maximum
  
As Reported on the
  
Maximum
Company
  
Balance Sheet
  
Exposure
  
Balance Sheet
  
Exposure
   
(in thousands)
APCo
  
$
 12,440 
  
$
 12,440 
  
$
 29,819 
  
$
 29,819 
I&M
    
 7,764 
    
 7,764 
    
 17,911 
    
 17,911 
OPCo
    
 16,800 
    
 16,800 
    
 39,323 
    
 39,323 
PSO
    
 5,380 
    
 5,380 
    
 13,381 
    
 13,381 
SWEPCo
    
 8,801 
    
 8,801 
    
 19,669 
    
 19,669 

AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP.  AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station.  AEGCo sells all the output from the Rockport Plant to I&M and KPCo.   AEGCo leases the Lawrenceburg Generating Station to OPCo.  AEP guarantees all the debt obligations of AEGCo.  I&M and OPCo are considered to have a significant interest in AEGCo due to these transactions.  I&M and OPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations.  In the event AEGCo would require financing or other support outside the billings to I&M, OPCo and KPCo, this financing would be provided by AEP.  For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 11 in the 2012 Annual Report.

Total billings from AEGCo were as follows:

                         
   
Three Months Ended June 30,
  
Six Months Ended June 30,
Company
  
2013 
  
2012 
  
2013 
  
2012 
   
(in thousands)
I&M
  
$
 53,191 
  
$
 53,917 
  
$
 111,726 
  
$
 112,739 
OPCo
    
 31,910 
    
 44,823 
    
 70,621 
    
 103,239 

The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows:
 
                         
   
June 30, 2013
  
December 31, 2012
   
As Reported on
  
Maximum
  
As Reported on
  
Maximum
Company
  
the Balance Sheet
  
Exposure
  
the Balance Sheet
  
Exposure
   
(in thousands)
I&M
  
$
 20,126 
  
$
 20,126 
  
$
 25,498 
  
$
 25,498 
OPCo
    
 12,771 
    
 12,771 
    
 16,302 
    
 16,302 

 
218
 
13.  SUSTAINABLE COST REDUCTIONS

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

The Registrant Subsidiaries recorded charges to Other Operation expense in 2012 primarily related to severance benefits as a result of the sustainable cost reductions initiative.  The total amount incurred in 2012 by Registrant Subsidiary was as follows:

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

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

           
Expense
  
Incurred for
              
Remaining
     
Balance as of
  
Allocation from
  
Registrant
            
Balance as of
 
Company
  
 December 31, 2012
  
    AEPSC
  
Subsidiaries
  
Settled
  
Adjustments
  
 June 30, 2013
     
(in thousands)
 
APCo
  
$
 1,321 
  
$
 1,355 
  
$
 - 
  
$
 (1,908)
  
$
 (735)
  
$
 33 
 
I&M
    
 1,357 
    
 953 
    
 - 
    
 (1,882)
    
 (379)
    
 49 
 
OPCo
    
 3,450 
    
 1,834 
    
 6,114 
    
 (8,413)
    
 (1,648)
    
 1,337 
 
PSO
    
 652 
    
 487 
    
 - 
    
 (642)
    
 (472)
    
 25 
 
SWEPCo
    
 627 
    
 864 
    
 - 
    
 (1,789)
    
 405 
    
 107 

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

 
219
 

COMBINED MANAGEMENT’S NARRATIVE DISCUSSION
AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the Registrant Subsidiaries’ management’s discussion and analysis.  The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (a) Management’s Narrative Discussion and Analysis of Results of Operations, (b) financial statements, (c) footnotes and (d) the schedules of each individual registrant.  The Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries section of the 2012 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

Customer Demand

In comparison to 2012, weather-normalized retail sales across the AEP System were down 2.7% and 2.1% for the three and six months ended June 30, 2013, respectively.  Industrial sales across the AEP System declined 5.3% and 5.7%, respectively, partially due to Ormet, OPCo's large aluminum customer that lowered their production in the third quarter of 2012 by one-third and is currently in bankruptcy proceedings.

ENVIRONMENTAL ISSUES

The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with environmental control requirements.  The Registrant Subsidiaries will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.

The Registrant Subsidiaries are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of I&M’s nuclear units.  AEP, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court.  Management is also engaged in the development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change.  Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

See a complete discussion of these matters in the “Environmental Issues” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2012 Annual Report.  Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Recovery in Ohio will be dependent upon prevailing market conditions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If the costs of environmental compliance are not recovered, it would reduce future net income and cash flows and impact financial condition.
 
220
 

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of June 30, 2013, the AEP System had a total generating capacity of 37,600 MWs, of which 23,700 MWs are coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the coal-fired generating facilities.  For the Registrant Subsidiaries, management’s current ranges of estimates of environmental investments to comply with these proposed requirements are listed below:

     
Through 2020
     
Estimated Environmental Investment
Company
  
Low
  
High
   
(in millions)
APCo
  
$
 330 
  
$
 440 
I&M
    
 510 
    
 610 
OPCo
    
 840 
    
 1,080 
PSO
    
 310 
    
 380 
SWEPCo
    
 1,430 
    
 1,750 

For APCo and I&M, the projected environmental investments above include the conversion of 470 MWs and 500 MWs, respectively, of coal generation to natural gas capacity.  If natural gas conversion is not completed, the units could be closed sooner than planned.

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

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

Subject to the factors listed above and based upon continuing evaluation, management intends to retire the following plants or units of plants before or during 2016:

       
Generating
Company
  
Plant Name and Unit
  
Capacity
       
(in MWs)
APCo
  
Clinch River Plant, Unit 3
    
 235 
APCo
  
Glen Lyn Plant
    
 335 
APCo
  
Kanawha River Plant
    
 400 
APCo/OPCo
  
Philip Sporn Plant, Units 1-4
    
 600 
I&M
  
Tanners Creek Plant, Units 1-3
    
 495 
OPCo
  
Kammer Plant
    
 630 
OPCo
  
Muskingum River Plant, Units 1-5
    
 1,440 
OPCo
  
Picway Plant
    
 100 
PSO
  
Northeastern Station, Unit 4
    
 470 
SWEPCo
  
Welsh Plant, Unit 2
    
 528 

As of June 30, 2013, the net book value of all of OPCo’s units above is zero and the net book value including related inventory and CWIP balances of the other plants in the table above was $592 million.
 
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In the second quarter of 2013, management re-evaluated potential courses of action with respect to the planned operation of Muskingum River Plant, Unit 5 and concluded that completion of a refueling project which would extend the unit’s useful life is remote.  As a result, in the second quarter of 2013, management completed an impairment analysis and recorded a $154 million pretax ($99 million, net of tax) impairment charge for OPCo’s net book value of Muskingum River Plant, Unit 5.  Management expects to retire the plant no later than 2015.  See “Muskingum River Plant, Unit 5” section of Note 5.

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

       
Generating
Company
  
Plant Name and Unit
  
Capacity
       
(in MWs)
APCo
  
Clinch River Plant, Units 1-2
    
 470 
I&M/AEGCo/KPCo
  
Rockport Plant, Units 1-2
    
 2,620 
I&M
  
Tanners Creek Plant, Unit 4
    
 500 
PSO
  
Northeastern Station, Unit 3
    
 460 

As of June 30, 2013, the net book values including related inventory and CWIP balances of the plants in the table above were $1.2 billion.

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

Modification of the New Source Review (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 consent decree requires 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.  In January 2013, an agreement to modify the consent decree was reached and filed with the court.  The terms of the agreement include more options for the affected units (including alternative control technologies, re-fueling and/or retirement), more stringent SO2 emission caps for the AEP System and additional mitigation measures.  The Federal EPA sought public comments on the modification prior to its entry by the court in May 2013.  For the units of the Rockport Plant, the modified decree requires installation of dry sorbent injection technology for SO2 control on both units in 2015 and imposes a declining plant-wide cap on SO2 emissions beginning in 2016.

Clean Air Act Requirements

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

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas.  BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.  CAVR will be implemented through individual
 
 
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state implementation plans (SIPs) or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs).  The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas and Oklahoma.  The Federal EPA finalized a FIP for Oklahoma that contains more stringent control requirements for SO2 emissions from affected units in that state.  The Arkansas SIP was disapproved and the state is developing a revised submittal.  In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the Cross-State Air Pollution Rule (CSAPR) trading programs to use those programs in place of source-specific BART for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states.  This rule is being challenged in the U.S. Court of Appeals for the District of Columbia Circuit and its fate is uncertain given developments in the CSAPR litigation.

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

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

Cross-State Air Pollution Rule (CSAPR)

In August 2011, the Federal EPA issued CSAPR.  Certain revisions to the rule were finalized in March 2012.  CSAPR relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states.  Interstate trading of allowances was allowed on a restricted sub-regional basis.  Arkansas and Louisiana are subject only to the seasonal NOx program in the rule.  Texas is subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program.  The annual SO2 allowance budgets in Indiana, Ohio and West Virginia were reduced significantly in the rule.  A supplemental rule includes Oklahoma in the seasonal NOx program.  The supplemental rule was finalized in December 2011 with an increased NOx emission budget for the 2012 compliance year.  The Federal EPA issued a final Error Corrections Rule and further CSAPR revisions in 2012 to make corrections to state budgets and unit allocations and to remove the restrictions on interstate trading in the first phase of CSAPR.

Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit.  Several of the petitioners filed motions to stay the implementation of the rule pending judicial review.  In December 2011, the court granted the motions for stay.  In August 2012, the panel issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the Clean Air Interstate Rule until a replacement rule is finalized.  The majority determined that the CAA does not allow the Federal EPA to “overcontrol” emissions in an upwind state and that the Federal EPA exceeded its statutory authority by failing to allow states an opportunity to develop their own implementation plans before issuing a FIP.  The Federal EPA and other respondents filed petitions for rehearing but in January 2013, the U.S. Court of Appeals for the District of Columbia Circuit denied all petitions for rehearing.  The petition for further review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013.  Separate appeals of the supplemental rule, the Error Corrections Rule and the further revisions have been filed, but are being held in abeyance.

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

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In February 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal, on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  The effective date of the final rule was April 16, 2012 and
 
 
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compliance is required within three years.  The AEP System is participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed.  In 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards.  Revisions to the new source standards consistent with the proposed rule, except for the start-up and shut down provisions, were issued by the Federal EPA in March 2013.  The Federal EPA has reopened the public comment period to consider additional changes to the start-up and shut down provisions.
 
 
The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and allows operators to exclude periods of startup and shutdown from the emissions averaging periods.  The compliance time frame remains a serious concern.  A one-year administrative extension may be available if the extension is necessary for the installation of controls or to avoid a serious reliability problem.  In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades.  Management is concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines.  The AEP System is participating in petitions for review filed in the U.S. Court of Appeals for the District of Columbia Circuit by several organizations in which the Registrant Subsidiaries are members.  Certain issues related to the standards for new coal-fired units have been severed from the main case and are being held in abeyance pending completion of the Federal EPA’s reconsideration proceeding.  The case is proceeding on the remaining issues and briefing was completed in April 2013.

Regional Haze – Affecting PSO

In 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze SIP submitted by the State of Oklahoma through the Department of Environmental Quality.  The Federal EPA proposed to approve all of the NOx control measures in the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO.  The Federal EPA proposed a FIP that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP.  The Federal EPA finalized the FIP in December 2011 that mirrored the proposed rule but established a five-year compliance schedule.  PSO filed a petition for review of the FIP in the Tenth Circuit Court of Appeals and engaged in settlement discussions with the Federal EPA, the State of Oklahoma and other parties.  In November 2012, PSO notified the court that the parties had reached agreement on a settlement that would provide for submission of a revised Regional Haze SIP requiring the retirement of one coal-fired unit of PSO’s Northeastern Station no later than 2016, installation of emission controls on the second coal-fired Northeastern unit in 2016 and retirement of the second unit no later than 2026.  The Tenth Circuit Court of Appeals is holding the appeal in abeyance pending implementation of the settlement.  A revised regional haze SIP has been adopted by the State of Oklahoma and submitted to the Federal EPA for review.

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.
 
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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.  A proposal was sent to the Office of Management and Budget for interagency review the following week, but the details of the proposal are not known.  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.  In developing this proposal, the President directed the Federal EPA to directly engage states, leaders in the power sector, labor leaders and other stakeholders, to tailor the regulations to reduce costs, to develop market-based instruments and allow regulatory flexibilities and “assure that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power.”  Management cannot currently predict the impact these programs may have on future resource plans or the existing generating fleet, but the costs may be substantial.

In June 2012, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO2 emissions from new motor vehicles and its plan to phase in regulation of CO2 emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs.  A petition for rehearing was filed which the court denied in December 2012.  Petitioners filed petitions for further review in the U.S. Supreme Court.

The Federal EPA also finalized a rule in June 2012 that retains the current CO2 emission thresholds for permitting stationary sources under the PSD and Title V operating permit programs at 100,000 tons per year for new sources and 75,000 tons per year for modified sources.  The Federal EPA also confirmed that it will re-evaluate these thresholds during its five-year review in 2016.  The AEP System’s generating units are large sources of CO2 emissions and management will continue to evaluate the permitting obligations in light of these thresholds.

Coal Combustion Residual Rule

In 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units.  The rule contains two alternative proposals.  One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management.  Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule.  In 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment.  The Federal EPA has also announced its intention to complete a risk assessment of various beneficial uses of coal ash. Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule.  The Federal EPA opposed the petition and is seeking additional time to coordinate the issuance of a final rule with the issuance of new effluent limitations under the Clean Water Act for utility facilities.

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

In 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling.  Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority.  Management is evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at the AEP System’s facilities.  In June 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments.  Management submitted comments in July 2012.  Issuance of a final rule is not expected until November 2013.  Management is preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

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

Climate Change

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

While comprehensive economy-wide regulation of CO2 emissions might be achieved through future legislation, Congress has yet to enact such legislation.  The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA.

Several states have adopted programs that directly regulate CO2 emissions from power plants.  The majority of the states where the Registrant Subsidiaries have generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements.  Management is taking steps to comply with these requirements.

Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others.  The Registrant Subsidiaries have been named in one remaining pending lawsuit, which management is defending.  It is not possible to predict the outcome of this lawsuit or its impact on operations or financial condition.  See “Carbon Dioxide Public Nuisance Claims” section of Note 4.
 
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Future federal and state legislation or regulations that mandate limits on the emission of CO2 would result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force the Registrant Subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets.  As a result, mandatory limits could reduce future net income and cash flows and impact financial condition.

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

ACCOUNTING PRONOUNCEMENTS

Future Accounting Changes

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

Item 4.  Controls and Procedures

During the second quarter of 2013, management, including the principal executive officer and principal financial officer of each of AEP, APCo, I&M, OPCo, PSO and SWEPCo (collectively, the Registrants), evaluated the Registrants’ disclosure controls and procedures.  Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of June 30, 2013, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.  The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the second quarter of 2013 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
 
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PART II.  OTHER INFORMATION

Item 1.     Legal Proceedings

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

Item 1A.  Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2012 includes a detailed discussion of risk factors.  The information presented below amends certain of those risk factors that have been updated and should be read in conjunction with the risk factors and information disclosed in the 2012 Annual Report on Form 10-K.

GENERAL RISKS OF OUR REGULATED OPERATIONS

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

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

We may not fully recover all of the investment in and expenses related to extending the useful life of the Cook Plant – Affecting AEP and I&M

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects for Cook Plant, Units 1 and 2 intended to ensure the safe and reliable operation of the plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of June 30, 2013, I&M has incurred $240 million related to the LCM Project, including AFUDC.  In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.  If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

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

In July 2012, SWEPCo filed a request with the PUCT for an annual increase in Texas base rates.  A portion of the increase seeks recovery for costs associated with the construction and operation of the Texas jurisdictional share (approximately 33%) of the Turk Plant.  In May 2013, the Administrative Law Judge issued a proposal for decision, and added clarifications in July 2013, that made various recommendations including (a) a reduction to both the requested annual base rate increase and the requested return on common equity, (b) the disallowance of the Turk Plant capital costs in excess of the investment and committed costs as of June 2010 plus the cost to retrofit Welsh Plant, Unit 2 which, as of June 30, 2013, SWEPCo estimates could result in a write-off of approximately $74 million (in excess of the $62 million reserve previously recorded related to the Texas capital cost cap) and (c) the exclusion, until SWEPCo’s next Texas base rate case, of the Turk Plant transmission line investment that was not in service at the end of the test year.  If SWEPCo cannot recover all of its Texas jurisdictional share of the investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.
 
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Request for rate recovery in Indiana may be overturned on appeal. – Affecting AEP and I&M

In February 2013, the IURC issued an order granting an annual increase in base rates.  In March 2013, the Indiana Office of Utility Consumer Counselor filed an appeal of the order with the Indiana Court of Appeals.  If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

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

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

RISKS RELATING TO STATE RESTRUCTURING

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

In October 2012, we submitted several filings with the FERC seeking approval to fully separate OPCo’s generating assets from its distribution and transmission operations.  The filings requested approval to transfer approximately 9,200 MW of OPCo-owned generation assets to a new competitive, unregulated generation affiliate.  We also requested approval from the FERC and, as applicable, the KPSC, the Virginia SCC and the WVPSC to transfer 1,647 MW of OPCo-owned generation assets to APCo and 780 MW of OPCo-owned generation assets to KPCo.  These transfers are proposed to be effective December 31, 2013.  The transfer of generation units co-owned by third parties will require the consent and cooperation of those third parties.  In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AEPGenCo, the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo and the merger of APCo and WPCo.  In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo.  OPCo has contested the petition for rehearing, which remains pending before the FERC.  Additionally, we asked for FERC approval to terminate the existing Interconnection Agreement and to authorize a new Power Coordination Agreement among APCo, I&M and KPCo.  Significant gaps could emerge if the Interconnection Agreement is terminated without approval of the generation asset transfers and/or the new Power Coordination Agreement.  Surplus members would no longer automatically sell to deficit members, and they may not be able to otherwise sell that surplus in amounts or at rates equal to what they obtained under the Interconnection Agreement.  Conversely, deficit members would no longer automatically purchase from surplus members, and they may not be able to otherwise purchase in amounts or at rates equal to what they obtained under the Interconnection Agreement.  The possible loss of these sales by the surplus members and the potential increase in costs for the deficit members could reduce future net income and cash flows.  In addition, we can give no assurance that the FERC or other state commissions will not impose material adverse terms as a condition to approving these arrangements and asset transfers.  Further, third party co-owners may not consent to the transfers where applicable.

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

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

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

None
 
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Item 4.  Mine Safety Disclosures

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations.  The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters.  SWEPCo, through its ownership of DHLC, and OPCo, through its ownership of Conesville Coal Preparation Company (CCPC) and use of the Conner Run fly ash impoundment, are subject to the provisions of the Mine Act.  OPCo sold CCPC in April 2013.  Consequently, this will be the last quarterly report to make reference to CCPC.

The Dodd-Frank Wall Street Reform and Consumer Protection Act and its related regulations require companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act.  Exhibit 95 contains the notices of violation and proposed assessments received by DHLC, CCPC and Conner Run under the Mine Act for the quarter ended June 30, 2013.

Item 5.  Other Information

None

Item 6.  Exhibits

4 – Modification of $1 Billion Term Credit Agreement Dated July 2013

10 – Third Joint Modification to Consent Decree with Order Modifying Consent Decree Dated May 2013

12 – Computation of Consolidated Ratio of Earnings to Fixed Charges

31(a) – Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31(b) – Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32(a) – Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
32(b) – Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

95 – Mine Safety Disclosures

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

 
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SIGNATURE




Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.  The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.


AMERICAN ELECTRIC POWER COMPANY, INC.



 
By: /s/ Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer




APPALACHIAN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY



 

 
By: /s/ Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer



Date:  July 26, 2013


 
231