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 March 31,June 30, 2014
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.
      
YesX 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).
      
YesX 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 filerX 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 filerX Smaller reporting company  

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
Yes  NoX 
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.




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
April 23, 2014
 July 24, 2014
  
American Electric Power Company, Inc.488,670,382488,083,018
 ($6.50 par value)
Appalachian Power Company13,499,50013,499,500
 (no par value)
Indiana Michigan Power Company1,400,0001,400,000
 (no par value)
Ohio Power Company27,952,47327,952,473
 (no par value)
Public Service Company of Oklahoma9,013,0009,013,000
 ($15 par value)
Southwestern Electric Power Company7,536,6407,536,640
 ($18 par value)



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
March 31, 2014
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
June 30, 2014
     
    Page
    Number
Glossary of Terms
i
     
Forward-Looking Information
iv
     
Part I. FINANCIAL INFORMATION 
     
 Items 1, 2, 3 and 4 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Controls and Procedures: 
     
American Electric Power Company, Inc. and Subsidiary Companies: 
 Management’s Discussion and Analysis of Financial Condition and Results of Operations
1
 Condensed Consolidated Financial Statements29
38
 Index of Condensed Notes to Condensed Consolidated Financial Statements35
44
     
Appalachian Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations74
98
 Condensed Consolidated Financial Statements78
103
 Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries84
109
     
Indiana Michigan Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations86
111
 Condensed Consolidated Financial Statements90
116
 Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries96
122
     
Ohio Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations98
124
 Condensed Consolidated Financial Statements103
131
 Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries109
137
     
Public Service Company of Oklahoma: 
 Management’s Narrative Discussion and Analysis of Results of Operations111
139
 Condensed Financial Statements114
143
 Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries120
149
     
Southwestern Electric Power Company Consolidated: 
 Management’s Narrative Discussion and Analysis of Results of Operations122
151
 Condensed Consolidated Financial Statements125
157
 Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries131
163
     
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries132
164
     
Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries186
243
     
Controls and Procedures
250



     192
Part II.  OTHER INFORMATION 
 
Item 1.  Legal Proceedings
250
Item 1A.  Risk Factors
251
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
252
Item 4.  Mine Safety Disclosures
252
Item 5.  Other Information
253
Item 6.  Exhibits:
253
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
254
     
     
Item 1.  Legal Proceedings193
Item 1A.  Risk Factors193
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds194
Item 4.  Mine Safety Disclosures194
Item 5.  Other Information194
Item 6.  Exhibits:194
  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
SIGNATURE195
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.
AEP System American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP Transmission Holdco 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.
AEPTCoAEP Transmission Company, LLC, a subsidiary of AEP Transmission Holdco and an intermediate holding company that owns seven wholly-owned transmission companies.
AGR AEP Generation Resources Inc., a nonregulated AEP subsidiary in the Generation & Marketing segment.
AFUDC Allowance for Funds Used During Construction.
AOCI Accumulated Other Comprehensive Income.
APCo Appalachian Power Company, an AEP electric utility subsidiary.
Appalachian Consumer Rate Relief Funding Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
ASU Accounting Standards Update.
BlueStarBlueStar 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 provider Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation 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, DCC Fuel V LLC and DCC Fuel VI 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.
ENEC Expanded Net Energy Charge.
Energy SupplyAEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
ERCOT Electric Reliability Council of Texas regional transmission organization.
i
TermMeaning
ESP Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.

i


TermMeaning
ETT Electric Transmission Texas, LLC, an equity interest joint venture between AEP and MidAmericanBerkshire Hathaway Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FAC Fuel Adjustment Clause.
FASB Financial Accounting Standards Board.
Federal EPA United States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
FGD Flue Gas Desulfurization or scrubbers.
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, which defined the sharing of costs and benefits associated with their respective generation plants. This agreement was terminated January 1, 2014.
IRS Internal Revenue Service.
IURC Indiana Utility Regulatory Commission.
KGPCo Kingsport Power Company, an AEP electric utility subsidiary.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSC Kentucky Public Service Commission.
KWh Kilowatthour.
LPSC Louisiana Public Service Commission.
MISO Midwest Independent Transmission System Operator.
MMBtu Million British Thermal Units.
MPSC Michigan Public Service Commission.
MTM Mark-to-Market.
MW Megawatt.
MWh Megawatthour.
NOx
 Nitrogen oxide.
Nonutility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NSR New Source Review.
OCC Corporation Commission of the State of Oklahoma.
Ohio Phase-in-Recovery Funding Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
OPEB Other Postretirement Benefit Plans.
Operating AgreementAgreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third party sales. AEPSC acts as the agent.
OTC Over the counter.
OVEC Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PIRR Phase-In Recovery Rider.
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.
ii
TermMeaning
PUCO Public Utilities Commission of Ohio.
PUCT Public Utility Commission of Texas.

ii


TermMeaning
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 generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.  AEGCo and I&M jointly-own Unit 1.  In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
RPM Reliability Pricing Model.
RSR Retail Stability Rider.
RTO Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC U.S. Securities and Exchange Commission.
SEET Significantly Excessive Earnings Test.
SIA System Integration Agreement, effective June 15, 2000, as amended, 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 534 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.
Texas Restructuring Legislation Legislation enacted in 1999 to restructure the electric utility industry in Texas.
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 Legislation.
Transource Energy Transource Energy, LLC, a consolidated variable interest entity formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.
Transource Missouri A 100% wholly-owned subsidiary of Transource Energy.
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 2013 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:

·
ŸThe economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory.
·ŸInflationary or deflationary interest rate trends.
·ŸVolatility 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.
·ŸThe 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.
·ŸElectric load, customer growth and the impact of retail competition, particularly in Ohio.competition.
·ŸWeather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs.
·ŸAvailable sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·ŸAvailability of necessary generation capacity and the performance of our generation plants.
·ŸOur ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·ŸOur ability to build or acquire generation 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.
·ŸNew 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, cost recovery and/or profitability of our generation plants and related assets.
·ŸEvolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
·ŸA reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
·ŸTiming 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.
·ŸResolution of litigation.
·ŸOur ability to constrain operation and maintenance costs.
·ŸOur ability to develop and execute a strategy based on a view regarding prices of electricity and other energy-related commodities.
·ŸPrices and demand for power that we generate and sell at wholesale.
·ŸChanges in technology, particularly with respect to new, developing, alternative or distributed sources of generation.
·ŸOur ability to recover through rates or market prices any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.

iv


·
ŸVolatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.
·ŸChanges in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP.
iv
·ŸThe transition to market for generation in Ohio, including the implementation of ESPs.
·ŸOur ability to successfully and profitably manage our separate competitive generation assets.
·ŸChanges in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·ŸActions of rating agencies, including changes in the ratings of our debt.
·ŸThe 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 of such volatility on future funding requirements.
·ŸAccounting pronouncements periodically issued by accounting standard-setting bodies.
·ŸOther 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 2013 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

Customer Demand

In comparison to 2013, heating degree days for the six months ended June 30, 2014 were up 32% in our western region and 20% in our eastern region. Our weather-normalized retail sales volumes for the second quarter of 2014 decreased by 0.5% from their levels for the second quarter of 2013 and increased by 0.6% for the first six months of 2014 from their levels for the first six months of 2013. In comparison to 2013, our industrial sales volume decreased 0.5% and 1.6% for the three and six months ended June 30, 2014, respectively, due mainly to the closure of Ormet, a large aluminum company. Excluding Ormet, our six months ended June 30, 2014 industrial sales volumes increased 3.4% over the six months ended June 30, 2013. Following Ormet's closure in October 2013, the loss of Ormet's load will not have a material impact on future gross margin because power previously sold to Ormet will be available for sale into generally higher priced wholesale markets.

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) wholesale sales, (c) deferral of unrecovered capacity costs, (d) RSR collections and (e) revenues from AEP Energy. AEP Energy is our CRES provider and part of our Generation & Marketing segment which targets retail customers, both within and outside of our retail service territory.

Ohio Electric Security Plan FilingFilings

2009 –- 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. As of March 31,June 30, 2014, OPCo’s net deferred fuel balance was $426$411 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 balance.balance up to the full amount.
 
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. This ruling was generally upheld in PUCO rehearing orders in January and March 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the 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 OPCo RPM price collected from CRES providers, which includes reserve margins, iswas approximately $33/$34/MW day through May 2014 and $148/is $150/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR is beingwas collected from customers at $3.50/MWh through May 2014 and will beis currently collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April

1


and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR. As of March 31,June 30, 2014, OPCo’s incurred deferred capacity costs balance was $348$396 million, including debt carrying costs.

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. In February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. In May 2014, OPCo conducted an additional energy-only auction for 25% of the SSO load with delivery beginning November 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50%25% of the SSO load with delivery beginning November 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. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 –- 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In May 2014, an independent auditor was selected by the PUCO and an audit of the recovery of the fixed fuel costs began in June 2014. A final audit report is expected in the third quarter of 2014.

Proposed June 2015 –- May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018. This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to market.competitively procured SSO supply. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo. The proposal also includes a purchased power agreement rider (PPA) that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based purchase power agreement. Additionally, the
1
application identifies OPCo’s intention to submitin July 2014, OPCo submitted a separate application to continue the RSR established in the June 2012 –- May 2015 ESP in whichto collect the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. Management intends to file this application inIn May 2014, intervenors and the second quarterPUCO staff filed testimony that provided various recommendations including the rejection and/or modification of 2014.  A hearingvarious riders, including the Distribution Investment Rider and the proposed PPA. Hearings at the PUCO in the ESP case is scheduled forwere held in June 2014.

If OPCo is ultimately not permitted to fully collect its ESP rates, including the RSR, its deferred fuel balance and its deferred capacity cost, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filing”Filings” section of Note 4.

Ohio Customer Choice2012 Texas Base Rate Case

In our Ohio service territory, various CRES providers are targeting retail customers by offering alternative generation service.  The reductionUpon rehearing in gross margin asJanuary 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap.  As a result, of customer switching in Ohio is partially offset by (a) collection of capacity revenues from CRES providers, (b) wholesale sales, (c) deferral of unrecovered capacity costs, (d) RSR collections and (e) revenues from AEP Energy.  AEP Energy is our CRES provider and part of our Generation & Marketing segment which targets retail customers, both within and outside of our retail service territory.

Customer Demand

In comparison to 2013, heating degree days in 2014 were up 40% in our western region and 24% in our eastern region.  Our weather-normalized retail sales volumes for the first quarter of 2014 increased by 1.5% from their levels for the first quarter of 2013.  First quarter 2014 weather-adjusted residential and commercial customer sales were up 4.4% and 2.9%, respectively, from their levels for the first quarter of 2013.  Residential and commercial customer counts grew 0.4% and 0.8% in the first quarter of 2014, respectively, from the first quarter of 2013.

Our industrial sales volumes in the first quarter 2014 decreased 2.9% from the firstfourth quarter of 2013, due mainly toSWEPCo reversed $114 million of previously recorded regulatory disallowances.  The resulting annual base rate increase is approximately $52 million.  In May 2014, intervenors filed appeals of the closureorder with the Texas District Court.  In June 2014, SWEPCo intervened in those appeals and filed initial responses.  If any part of Ormet, a large aluminum company.  Ormet had a contract to purchase power from OPCo through 2018.  In October 2013, Ormet announced thatthe PUCT order is overturned it was unable to emerge from bankruptcycould reduce future net income and shut down its operations effective immediately.  Excluding Ormet, our first quarter 2014 industrial sales volumes increased 2.2% overcash flows and impact financial condition.  See the first quarter“2012 Texas Base Rate Case” section of 2013.  The loss of Ormet's load will not have a material impact on future gross margin because power previously sold to Ormet will be available for sale into generally higher priced wholesale markets.Note 4.

PJM Capacity Market

Through May 2015, AGR will provide generation capacity to OPCo for both switched and non-switched OPCo generation customers.  AGR is required to offer all of its remaining generation capacity in the PJM RPM auction, which is conducted three years in advance of the actual delivery year.  AGR generation assets are subject to PJM capacity prices for periods after May 2015.  For switched customers, OPCo pays AGR $188.88/MW day.  For non-switched OPCo generation customers, OPCo pays AGR for capacity.  AGR’s non-OPCo load is subject to the PJM RPM auction.  Shown below are the current auction prices for capacity, as announced/settled by PJM:

PJM Base
PJM Auction PeriodAuction Price
(per MW day) 
June 2013 through May 2014$ 27.73 
June 2014 through May 2015 125.99 
June 2015 through May 2016 136.00 
June 2016 through May 2017 59.37 

Due to the volatility and uncertainty in prices, we formed a coalition with other utility companies to address mutual concerns related to the PJM capacity auction process, including: (a) import limits for power without firm transmission, (b) placing bidding caps on available demand response resources in comparison to base generation capacity, (c) modification and enforcement of the timing of demand response requirements to better reflect real-time capacity requirements and (d) tightened rules for incremental auctions in which speculative bidders currently can sell resources in the base auction and buy back that capacity in an incremental auction, resulting in no additional capacity and lower auction prices.  PJM has made four FERC filings related to those issues.  In January 2014, FERC
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accepted without modification PJM's filed recommendations on placing bidding caps on certain demand response products that are available only during the summer period.  We expect to receive FERC decisions on the other filings prior to the next RPM auction in May 2014.


2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant. In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013. The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant.  If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition. See the “2012 Louisiana Formula Rate Filing” section of Note 4.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC.  Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC.  As of March 31, 2014, SWEPCo has incurred $48 million in costs related to these projects.  SWEPCo will seek to recover these project costs from its state commissions and FERC customers.

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years.

In AprilJune 2014, a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors was filed with the OCC. The parties to the stipulation recommended no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider would provide $7 million of revenues in 2014 and increases to $27 million in 2016. New depreciation rates are recommended for advanced metering investments and existing meters, to be effective November 2014. Additionally, the stipulation recommends recovery of regulatory assets for 2013 storms and regulatory case expenses. In July 2014, the OCC Staff and intervenors filed testimony with various recommendations.Attorney General joined in the stipulation agreement. A hearing at the OCC is scheduled for Junewas held in July 2014. If the OCC were to disallow any portion of this settlement agreement, it could reduce future net income and cash flows and impact financial condition. See the "2014“2014 Oklahoma Base Rate Case"Case” section of Note 4.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a biennial generation and distribution base rate biennial reviewcase with the Virginia SCC. In accordance with a Virginia statute, APCo did not request an increase in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to the change in the expected service life of certain plants. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to certainIGCC and other deferred costs. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 Virginia Biennial Base Rate Case” section of Note 4.

2014 West Virginia Base Rate Case

In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $181 million, based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates and requested amortization of $89 million over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $45 million annually to recover total vegetation management costs. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 West Virginia Base Rate Case” section of Note 4.

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PJM Capacity Market

AGR is required to offer all of its available generation capacity in the PJM RPM auction, which is conducted three years in advance of the actual delivery year. Therefore, the majority of AGR generation assets are subject to PJM capacity prices for periods after May 2015. Through May 2015, AGR will provide generation capacity to OPCo for both switched and non-switched OPCo generation customers. For switched customers, OPCo pays AGR $188.88/MW day for capacity. For non-switched OPCo generation customers, OPCo pays AGR its blended tariff rate for capacity consisting of $188.88/MW day for auctioned load and the non-fuel generation portion of its base rate for non-auctioned load. AGR’s excess capacity is subject to the PJM RPM auction. Shown below are the current auction prices for capacity, as announced/settled by PJM:
  PJM Base
PJM Auction Period Auction Price
  (per MW day)
June 2013 through May 2014 $27.73
June 2014 through May 2015  125.99
June 2015 through May 2016  136.00
June 2016 through May 2017  59.37
June 2017 through May 2018  120.00

We expect a significant decline in AGR capacity revenues after May 2015 when the Power Supply Agreement between AGR and OPCo ends. Additionally, we expect a decline in AGR capacity revenues from June 2016 through May 2017 based upon the decrease in the PJM base auction price.

In 2013, AEP formed a coalition with other utility companies to address mutual concerns related to the PJM capacity auction process. The advocacy work included: (a) assuring that capacity imports had firm transmission and could be dispatched by PJM as well as establishing more limiting criteria, (b) placing limits on the number of MWs of summer-only demand response to assure more year-round reliability, (c) modification and enforcement of the dispatch of demand response to better reflect real-time capacity requirements and (d) tightening of rules for incremental auctions in which speculative bidders sell resources in the base auction and buy back that capacity in an incremental auction, resulting in no additional capacity and artificially suppressing market prices.

PJM made four FERC filings related to these four issues beginning in the fall of 2013. FERC accepted the majority of the PJM recommendations in the first three filings. However, FERC rejected the fourth filing on incremental auctions, but set the docket for a technical conference for further discussion.

SPP Integrated Power Market

In March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In the past, PSO and SWEPCo would satisfy their load requirements with their own generation resources or through the Operating Agreement. In the new integrated power market, PSO and SWEPCo operate as standalone entities by offering their respective generation into the SPP power market, which then economically dispatches the resources. This change further enables retail customers to obtain low cost power through either internal generation or power purchases from the SPP market. The new integrated power market now operates in a similar manner as the PJM power market for the AEP East Companies. No significant impact on results of operations is expected due to this change.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC. As of June 30, 2014, SWEPCo has incurred $72 million in costs related to these projects. SWEPCo will seek to recover these project costs from customers through filings at the state commissions and FERC. These environmental projects could be impacted

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by pending carbon emission regulations.  See "CO2 Regulation"  section of “Environmental Issues” below.  As of June 30, 2014, the net book value of Welsh Plant, Units 1 and 3 was $297 million, before cost of removal, including materials and supplies inventory and CWIP.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 

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 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 March 31,June 30, 2014, I&M has incurred costs of $405$439 million related to the LCM Project, including AFUDC.

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In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items which the IURC stated I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC. In May 2014, the IURC issued a final order approving the LCM rider rates that were implemented in January 2014.

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

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition. See “Cook Plant Life Cycle Management Project (LCM Project)” section of Note 4.

LITIGATIONRESULTS OF OPERATIONS


EXECUTIVE OVERVIEW

Customer Demand

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficultcomparison 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 4 – Rate Matters, Note 6 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2013, Annual Report.  Additionally, see Note 4 – Rate Matters and Note 5 – 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.

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Courtheating degree days for the Southern Districtsix months ended June 30, 2014 were up 32% in our western region and 20% in our eastern region. Our weather-normalized retail sales volumes for the second quarter of New York against AEGCo2014 decreased by 0.5% from their levels for the second quarter of 2013 and I&M alleging that it will be unlawfully burdenedincreased by 0.6% for the termsfirst six months of 2014 from their levels for the modified NSR consent decree afterfirst six months of 2013. In comparison to 2013, our industrial sales volume decreased 0.5% and 1.6% for the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiff further alleges that the defendants’ actions constitute breach of the leasethree and participation agreement.  The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.  The New York court granted our motion to transfer this casesix months ended June 30, 2014, respectively, due mainly to the U.S. District Court forclosure of Ormet, a large aluminum company. Excluding Ormet, our six months ended June 30, 2014 industrial sales volumes increased 3.4% over the Southern District of Ohio.  Our motion to dismiss the case, filedsix months ended June 30, 2013. Following Ormet's closure in October 2013, is pending.  Wethe loss of Ormet's load will continue to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with environmental control requirements.  We will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.
We are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of our nuclear units.  We, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court.  We are also engaged in the development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change.  We believe that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

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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 2013 Annual Report.  We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If we are unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections willnot have a material impact on the generating unitsfuture gross margin because power previously sold to Ormet will be available for sale into generally higher priced wholesale markets.

Ohio Customer Choice

In our Ohio service territory, various CRES providers are targeting retail customers by offering alternative generation service. The reduction in thegross margin as a result of customer switching in Ohio is partially offset by (a) collection of capacity revenues from CRES providers, (b) wholesale sales, (c) deferral of unrecovered capacity costs, (d) RSR collections and (e) revenues from AEP System.  We continue to evaluate the impact of these rules, project scopeEnergy. AEP Energy is our CRES provider and technology available to achieve compliance.  As of March 31, 2014, 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, investment to meet these proposed requirements ranges from approximately $3 billion to $3.5 billion through 2020.  These amounts include investments to convert somepart of our coal generation to natural gas.  If natural gas conversion is not completed, the units could be retired sooner than planned.Generation & Marketing segment which targets retail customers, both within and outside of our retail service territory.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules.  The cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on our units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.  In addition, we are continuing to evaluate the economic feasibility of environmental investments on nonregulated plants.Ohio Electric Security Plan Filings

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 2016:2009 - 2011 ESP

Generating
CompanyPlant Name and UnitCapacity
(in MWs) 
APCoClinch River Plant, Unit 3 235 
APCoGlen Lyn Plant 335 
APCoKanawha River Plant 400 
APCo/AGRSporn Plant, Units 1-4 600 
I&MTanners Creek Plant, Units 1-4 995 
KPCoBig Sandy Plant, Unit 2 800 
AGRKammer Plant 630 
AGRMuskingum River Plant, Units 1-5 1,440 
AGRPicway Plant 100 
PSONortheastern Station, Unit 4 470 
SWEPCoWelsh Plant, Unit 2 528 
Total 6,533 

As of March 31, 2014,In August 2012, the net book value of the AGR units listed above was zero.  The net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the regulated plants in the table above was $974 million.
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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 unit that is either awaiting regulatory approval or are still being evaluated by management based on changes in emission requirements and demand for power:

Generating
CompanyPlant Name and UnitCapacity
(in MWs) 
KPCoBig Sandy Plant, Unit 1 278 

As of March 31, 2014, the net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the unit in the table above was $88 million.

PSO received Federal EPA approval of the Oklahoma SIP, in February 2014, related to the environmental compliance plan for Northeastern Station, Unit 3.

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.

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 the Clean Air Interstate Rule (CAIR) in 2005 requiring specific reductions in SO2 and NOx emissions from power plants.  In 2008, the District of Columbia Circuit Court of Appeals issued a decision remanding CAIR to the Federal EPA.  The Federal EPA issued the Cross-State Air Pollution Rule (CSAPR) (discussed in detail below) in August 2011 to replace CAIR.  The CSAPR was challenged in the courts.  The U.S. Court of Appeals for the District of Columbia CircuitPUCO issued an order in 2011 stayinga separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. As of June 30, 2014, OPCo’s net deferred fuel balance was $411 million, excluding unrecognized equity carrying costs. Decisions from the effective dateSupreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs balance up to the full amount.
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. This ruling was generally upheld in PUCO rehearing orders in January and March 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the 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 OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and is $150/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the rule pending judicial review.  In 2012, a panelcapacity costs decision with the Supreme Court of Ohio.

As part of the U.S. Court of Appeals forAugust 2012 ESP order, the District of Columbia Circuit issuedPUCO established a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing CAIR until a replacement rule is finalized.  That decision has been appealed to the U.S. Supreme Court.  Nearly all of the states in which our power plants are located are covered by CAIR.

non-bypassable RSR, effective September 2012. The Federal EPA issued the final maximum achievable control technology (MACT) standards for coal and oil-fired power plants in 2012.  See “Mercury and Other Hazardous Air Pollutants (HAPs) Regulation” section below.

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas.  BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.  CAVR will be implementedRSR was collected from customers at $3.50/MWh 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.  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 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.

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In 2009, the Federal EPA issued a final mandatory reporting rule for CO2 and other greenhouse gases covering a broad range of facilities emitting in excess of 25,000 tons of CO2 emissions per year.   The Federal EPA issued a final endangerment finding for greenhouse gas emissions from new motor vehicles in 2009.  The Federal EPA determined that greenhouse gas emissions from stationary sources will be subject to regulation under the CAA beginning January 2011 and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, SIP calls and FIPs.  The Federal EPA has proposed to include CO2 emissions in standards that apply to new electric utility units and will consider whether such standards are appropriate for other source categories in the future.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for PM, SO2, NOx and lead,May 2014 and is currently reviewingcollected at $4.00/MWh for the NAAQS for ozone.  States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for our facilities as a result of those evaluations.  We cannot currently predict the nature, stringency or timing of those requirements.

Notable developments in significant CAA regulatory requirements affecting our operations are discussed in the following sections.

Cross-State Air Pollution Rule (CSAPR)

In 2011, the Federal EPA issued CSAPR.  Certain revisionsperiod June 2014 through May 2015, with $1.00/MWh applied to the rule were finalized in 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 tradingrecovery of allowances is allowed on a restricted sub-regional basis.  Arkansas and Louisiana are subject only to the seasonal NOx program in the rule.  Texas is subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program.  The annual SO2 allowance budgets in Indiana, Ohio and West Virginia were reduced significantly in the 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.deferred capacity costs. In April

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Numerous affected entities, states and other partiesMay 2013, OPCo and various intervenors filed petitions to reviewappeals with the CSAPR in the U.S.Supreme Court of Appeals for the District of Columbia Circuit.  SeveralOhio challenging portions of the petitioners filed motions to stayPUCO’s ESP order, including the implementationRSR. As of the rule pending judicial review.  In 2011, the court granted the motions for stay.  In 2012, the court issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the CAIR 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 CourtJune 30, 2014, OPCo’s incurred deferred capacity costs balance 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$396 million, including debt carrying costs.

In 2012,November 2013, the Federal EPAPUCO issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.an order approving OPCo’s competitive bid process with modifications. 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,modifications include the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  The effective datedelay of the final rule was April 16, 2012 and compliance is required within three years.  We are participating through various organizationsenergy auctions that were originally ordered in the petitionsESP order. In February 2014, OPCo conducted an energy-only auction for administrative reconsideration10% of the SSO load with delivery beginning April 2014 through May 2015. In May 2014, OPCo conducted an additional energy-only auction for 25% of the SSO load with delivery beginning November 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 25% of the SSO load with delivery beginning November 2014 through May 2015 and judicial reviewfor 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. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that have been filed.  In 2012, the Federal EPA published a notice announcing that it would
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accept comments on its reconsideration of certain issuesintervenor concerns related to the new source standards, including clarificationrecovery of the requirements that apply during periods of start-up and shut down, measurement issuesfixed fuel costs through potentially both the FAC and the application of variability factorsapproved capacity charges be addressed in subsequent FAC proceedings. Management believes that may have an impact on the level of the standards.  The Federal EPA issued revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions in March 2013.  The Federal EPA is still considering 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.  Wethese intervenor concerns 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 participated in petitions for review filed in the U.S. Court of Appeals for the District of Columbia Circuit by several organizations of which we are members.  Certain issues related to the standards for new coal-fired units have been severed from the main case and are being held in abeyance pending completion of the Federal EPA’s reconsideration proceeding.  In April 2014, the appellate court issued a decision denying all of the petitions for review of the April 2012 final rule.

CO2 Regulation

In June 2013, President Obama issued a memorandum to the Administrator of the Federal EPA directing the agency to develop and issue a new proposal regulating carbon emissions from new electric generating units in September 2013.  The new proposal was issued in September 2013 and requires new large natural gas units to meet 1,000 pounds of CO2 per MWh of electricity generated and small natural gas units to meet 1,100 pounds of CO2 per MWh.  New coal-fired units are required to meet the 1,100 pounds of CO2 per MWh limit, with the option to meet the tighter limits if they choose to average emissions over multiple years.  This proposal was published in the Federal Register in January 2014.

The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from existing, modified and reconstructed electric generating units before June 2014, to finalize those standards by June 2015 and to require states to submit revisions to their implementation plans including such standards no later than June 2016.  The President directed the Federal EPA, in developing this proposal, to directly engage states, leaders in the power sector, labor leaders and other stakeholders, to tailor the regulations to reduce costs, to develop market-based instruments and allow regulatory flexibilities and “assure that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power.”  We cannot currently predict the impact these programs may have on future resource plans or our existing generating fleet, but the costs may be substantial.

In June 2012, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO2 emissions from new motor vehicles and its plan to phase in regulation of CO2 emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs.  A petition for rehearing was filed which the court denied in December 2012.  The U.S. Supreme Court granted several petitions for review and will determine whether the Federal EPA made a reasonable determination that adoption of the motor vehicle standards trigger PSD and Title V permitting obligations for stationary sources.  A decision is expected by June 2014.

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

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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 and also FGD gypsum generated at some coal fired plants.  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 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.  In 2013, the Federal EPA also issued a notice of data availability requesting comments on a narrow set of issues.

Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule.  The Federal EPA opposed the petition and sought additional time to coordinate the issuance of a final rule with the issuance of new effluent limitations under the Clean Water Act (CWA) for utility facilities.  In October 2013, the U.S. District Court for the District of Columbia issued a final order partially ruling in favor of the Federal EPA for dismissal of two counts, ruling in favor of the environmental organizations on one count and directing the Federal EPA to provide the court with a proposed schedule for completion of the rulemaking.without merit. In January 2014, the parties filedPUCO denied all rehearing requests and agreed to issue a motion withsupplemental request for an independent auditor in the court2012 - 2013 FAC proceeding to establish December 2014 asseparately examine the Federal EPA’s deadline for publicationrecovery of the rule.  The court will establish a deadline for the final rule following a comment period for interested parties.

In February 2014, the Federal EPA completed a risk evaluation of the beneficial uses of coal fly ash in concrete and flue gas desulfurization gypsum in wallboard and concluded that the Federal EPA supports these beneficial uses.  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.  We will incur significantfixed fuel 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 expected in 2014.  We are preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

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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 September 2015.  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 continue to review the proposal in detail to evaluate whether our plants are currently meeting the proposed limitations, what technologies have been incorporated into our long-range plans and what additional costs might be incurred if the Federal EPA's most stringent options were adopted.  We submitted detailed comments to the Federal EPA in September 2013 and participated in comments filed by various organizations of which we are members.

including OVEC. In March 2014, the Federal EPAPUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In May 2014, an independent auditor was selected by the PUCO and an audit of the recovery of the fixed fuel costs began in June 2014. A final audit report is expected in the third quarter of 2014.

Proposed June 2015 - May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the U.S. Army Corpscontinuation and modification of Engineers jointly announced that they will be issuingcertain existing riders effective June 2015 through May 2018. This filing is consistent with the PUCO’s objective for a proposed rulefull transition from FAC and base generation rates to clarifycompetitively procured SSO supply. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the scopethree-year term of the regulatory definition of “watersplan for customers who receive their RPM and energy auction-based generation through OPCo. The proposal also includes a purchased power agreement rider (PPA) that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based purchase power agreement. Additionally, in July 2014, OPCo submitted a separate application to continue the RSR established in the June 2012 - May 2015 ESP to collect the unrecovered portion of the United States” in lightdeferred capacity costs at the rate of recent U.S. Supreme Court cases and released a pre-publication version$4.00/MWh until the balance of the capacity deferrals has been collected. In May 2014, intervenors and the PUCO staff filed testimony that provided various recommendations including the rejection and/or modification of various riders, including the Distribution Investment Rider and the proposed rule.  The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters ofPPA. Hearings at the United States.”  This proposed jurisdictional definition will apply to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements.  Among those programs are: permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning.  We agree that clarity and efficiencyPUCO in the permitting processESP case were held in June 2014.

If OPCo is needed.  We are concerned thatultimately not permitted to fully collect its ESP rates, including the proposed rule introduces new concepts and could subject more of our operations to CWA jurisdiction, thereby increasing the time and complexity of permitting.  We will continue to evaluate the ruleRSR, its deferred fuel balance and its financial impact on the AEP System.  We plan to submit comments and also participate in the preparation of comments to be filed by various organizations of which we are members.

Climate Change

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

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.

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 limitsdeferred capacity cost, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filings” section of Note 4.

2012 Texas Base Rate Case

Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap.  As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances.  The resulting annual base rate increase is approximately $52 million.  In May 2014, intervenors filed appeals of the order with the Texas District Court.  In June 2014, SWEPCo intervened in those appeals and filed initial responses.  If any part of the PUCT order is overturned it could reduce future net income and cash flows and impact financial condition.  See the “2012 Texas Base Rate Case” section of Note 4.


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2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant. In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013. The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. 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 4.

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years.

In June 2014, a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors was filed with the OCC. The parties to the stipulation recommended no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider would provide $7 million of revenues in 2014 and increases to $27 million in 2016. New depreciation rates are recommended for advanced metering investments and existing meters, to be effective November 2014. Additionally, the stipulation recommends recovery of regulatory assets for 2013 storms and regulatory case expenses. In July 2014, the Attorney General joined in the stipulation agreement. A hearing at the OCC was held in July 2014. If the OCC were to disallow any portion of this settlement agreement, it could reduce future net income and cash flows and impact financial condition. See the “2014 Oklahoma Base Rate Case” section of Note 4.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a biennial generation and distribution base rate case with the Virginia SCC. In accordance with a Virginia statute, APCo did not request an increase in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to the change in the expected service life of certain plants. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to IGCC and other deferred costs. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 Virginia Biennial Base Rate Case” section of Note 4.

2014 West Virginia Base Rate Case

In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $181 million, based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates and requested amortization of $89 million over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $45 million annually to recover total vegetation management costs. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 West Virginia Base Rate Case” section of Note 4.

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PJM Capacity Market

AGR is required to offer all of its available generation capacity in the PJM RPM auction, which is conducted three years in advance of the actual delivery year. Therefore, the majority of AGR generation assets are subject to PJM capacity prices for periods after May 2015. Through May 2015, AGR will provide generation capacity to OPCo for both switched and non-switched OPCo generation customers. For switched customers, OPCo pays AGR $188.88/MW day for capacity. For non-switched OPCo generation customers, OPCo pays AGR its blended tariff rate for capacity consisting of $188.88/MW day for auctioned load and the non-fuel generation portion of its base rate for non-auctioned load. AGR’s excess capacity is subject to the PJM RPM auction. Shown below are the current auction prices for capacity, as announced/settled by PJM:
  PJM Base
PJM Auction Period Auction Price
  (per MW day)
June 2013 through May 2014 $27.73
June 2014 through May 2015  125.99
June 2015 through May 2016  136.00
June 2016 through May 2017  59.37
June 2017 through May 2018  120.00

We expect a significant decline in AGR capacity revenues after May 2015 when the Power Supply Agreement between AGR and OPCo ends. Additionally, we expect a decline in AGR capacity revenues from June 2016 through May 2017 based upon the decrease in the PJM base auction price.

In 2013, AEP formed a coalition with other utility companies to address mutual concerns related to the PJM capacity auction process. The advocacy work included: (a) assuring that capacity imports had firm transmission and could be dispatched by PJM as well as establishing more limiting criteria, (b) placing limits on the number of MWs of summer-only demand response to assure more year-round reliability, (c) modification and enforcement of the dispatch of demand response to better reflect real-time capacity requirements and (d) tightening of rules for incremental auctions in which speculative bidders sell resources in the base auction and buy back that capacity in an incremental auction, resulting in no additional capacity and artificially suppressing market prices.

PJM made four FERC filings related to these four issues beginning in the fall of 2013. FERC accepted the majority of the PJM recommendations in the first three filings. However, FERC rejected the fourth filing on incremental auctions, but set the docket for a technical conference for further discussion.

SPP Integrated Power Market

In March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In the past, PSO and SWEPCo would satisfy their load requirements with their own generation resources or through the Operating Agreement. In the new integrated power market, PSO and SWEPCo operate as standalone entities by offering their respective generation into the SPP power market, which then economically dispatches the resources. This change further enables retail customers to obtain low cost power through either internal generation or power purchases from the SPP market. The new integrated power market now operates in a similar manner as the PJM power market for the AEP East Companies. No significant impact on results of operations is expected due to this change.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC. As of June 30, 2014, SWEPCo has incurred $72 million in costs related to these projects. SWEPCo will seek to recover these project costs from customers through filings at the state commissions and FERC. These environmental projects could be impacted

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by pending carbon emission regulations.  See "CO2 Regulation"  section of “Environmental Issues” below.  As of June 30, 2014, the net book value of Welsh Plant, Units 1 and 3 was $297 million, before cost of removal, including materials and supplies inventory and CWIP.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 

For additional information on climate change, other environmental issuesCook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the actions we are taking to address potential impacts, see Part IMPSC, respectively, for approval of the 2013 Form 10-K underLCM Project, which consists of a group of capital projects to ensure the headings entitled “Environmentalsafe and Other Matters”reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and “Management’s Discussion and Analysis2037 for Unit 2). The estimated cost of Financial Condition and Resultsthe LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. As of Operations.”June 30, 2014, I&M has incurred costs of $439 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items which the IURC stated I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC. In May 2014, the IURC issued a final order approving the LCM rider rates that were implemented in January 2014.
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In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition. See “Cook Plant Life Cycle Management Project (LCM Project)” section of Note 4.

RESULTS OF OPERATIONS


EXECUTIVE OVERVIEW

Customer Demand

In comparison to 2013, heating degree days for the six months ended June 30, 2014 were up 32% in our western region and 20% in our eastern region. Our weather-normalized retail sales volumes for the second quarter of 2014 decreased by 0.5% from their levels for the second quarter of 2013 and increased by 0.6% for the first six months of 2014 from their levels for the first six months of 2013. In comparison to 2013, our industrial sales volume decreased 0.5% and 1.6% for the three and six months ended June 30, 2014, respectively, due mainly to the closure of Ormet, a large aluminum company. Excluding Ormet, our six months ended June 30, 2014 industrial sales volumes increased 3.4% over the six months ended June 30, 2013. Following Ormet's closure in October 2013, the loss of Ormet's load will not have a material impact on future gross margin because power previously sold to Ormet will be available for sale into generally higher priced wholesale markets.

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) wholesale sales, (c) deferral of unrecovered capacity costs, (d) RSR collections and (e) revenues from AEP Energy. AEP Energy is our CRES provider and part of our Generation & Marketing segment which targets retail customers, both within and outside of our retail service territory.

Ohio Electric Security Plan Filings

2009 - 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. As of June 30, 2014, OPCo’s net deferred fuel balance was $411 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 balance up to the full amount.
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. This ruling was generally upheld in PUCO rehearing orders in January and March 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the 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 OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and is $150/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50/MWh through May 2014 and is currently collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April

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and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR. As of June 30, 2014, OPCo’s incurred deferred capacity costs balance was $396 million, including debt carrying costs.

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. In February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. In May 2014, OPCo conducted an additional energy-only auction for 25% of the SSO load with delivery beginning November 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 25% of the SSO load with delivery beginning November 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. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In May 2014, an independent auditor was selected by the PUCO and an audit of the recovery of the fixed fuel costs began in June 2014. A final audit report is expected in the third quarter of 2014.

Proposed June 2015 - May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018. This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to competitively procured SSO supply. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo. The proposal also includes a purchased power agreement rider (PPA) that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based purchase power agreement. Additionally, in July 2014, OPCo submitted a separate application to continue the RSR established in the June 2012 - May 2015 ESP to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. In May 2014, intervenors and the PUCO staff filed testimony that provided various recommendations including the rejection and/or modification of various riders, including the Distribution Investment Rider and the proposed PPA. Hearings at the PUCO in the ESP case were held in June 2014.

If OPCo is ultimately not permitted to fully collect its ESP rates, including the RSR, its deferred fuel balance and its deferred capacity cost, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filings” section of Note 4.

2012 Texas Base Rate Case

Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap.  As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances.  The resulting annual base rate increase is approximately $52 million.  In May 2014, intervenors filed appeals of the order with the Texas District Court.  In June 2014, SWEPCo intervened in those appeals and filed initial responses.  If any part of the PUCT order is overturned it could reduce future net income and cash flows and impact financial condition.  See the “2012 Texas Base Rate Case” section of Note 4.


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2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant. In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013. The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. 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 4.

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years.

In June 2014, a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors was filed with the OCC. The parties to the stipulation recommended no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider would provide $7 million of revenues in 2014 and increases to $27 million in 2016. New depreciation rates are recommended for advanced metering investments and existing meters, to be effective November 2014. Additionally, the stipulation recommends recovery of regulatory assets for 2013 storms and regulatory case expenses. In July 2014, the Attorney General joined in the stipulation agreement. A hearing at the OCC was held in July 2014. If the OCC were to disallow any portion of this settlement agreement, it could reduce future net income and cash flows and impact financial condition. See the “2014 Oklahoma Base Rate Case” section of Note 4.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a biennial generation and distribution base rate case with the Virginia SCC. In accordance with a Virginia statute, APCo did not request an increase in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to the change in the expected service life of certain plants. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to IGCC and other deferred costs. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 Virginia Biennial Base Rate Case” section of Note 4.

2014 West Virginia Base Rate Case

In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $181 million, based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates and requested amortization of $89 million over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $45 million annually to recover total vegetation management costs. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 West Virginia Base Rate Case” section of Note 4.

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PJM Capacity Market

AGR is required to offer all of its available generation capacity in the PJM RPM auction, which is conducted three years in advance of the actual delivery year. Therefore, the majority of AGR generation assets are subject to PJM capacity prices for periods after May 2015. Through May 2015, AGR will provide generation capacity to OPCo for both switched and non-switched OPCo generation customers. For switched customers, OPCo pays AGR $188.88/MW day for capacity. For non-switched OPCo generation customers, OPCo pays AGR its blended tariff rate for capacity consisting of $188.88/MW day for auctioned load and the non-fuel generation portion of its base rate for non-auctioned load. AGR’s excess capacity is subject to the PJM RPM auction. Shown below are the current auction prices for capacity, as announced/settled by PJM:
  PJM Base
PJM Auction Period Auction Price
  (per MW day)
June 2013 through May 2014 $27.73
June 2014 through May 2015  125.99
June 2015 through May 2016  136.00
June 2016 through May 2017  59.37
June 2017 through May 2018  120.00

We expect a significant decline in AGR capacity revenues after May 2015 when the Power Supply Agreement between AGR and OPCo ends. Additionally, we expect a decline in AGR capacity revenues from June 2016 through May 2017 based upon the decrease in the PJM base auction price.

In 2013, AEP formed a coalition with other utility companies to address mutual concerns related to the PJM capacity auction process. The advocacy work included: (a) assuring that capacity imports had firm transmission and could be dispatched by PJM as well as establishing more limiting criteria, (b) placing limits on the number of MWs of summer-only demand response to assure more year-round reliability, (c) modification and enforcement of the dispatch of demand response to better reflect real-time capacity requirements and (d) tightening of rules for incremental auctions in which speculative bidders sell resources in the base auction and buy back that capacity in an incremental auction, resulting in no additional capacity and artificially suppressing market prices.

PJM made four FERC filings related to these four issues beginning in the fall of 2013. FERC accepted the majority of the PJM recommendations in the first three filings. However, FERC rejected the fourth filing on incremental auctions, but set the docket for a technical conference for further discussion.

SPP Integrated Power Market

In March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In the past, PSO and SWEPCo would satisfy their load requirements with their own generation resources or through the Operating Agreement. In the new integrated power market, PSO and SWEPCo operate as standalone entities by offering their respective generation into the SPP power market, which then economically dispatches the resources. This change further enables retail customers to obtain low cost power through either internal generation or power purchases from the SPP market. The new integrated power market now operates in a similar manner as the PJM power market for the AEP East Companies. No significant impact on results of operations is expected due to this change.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC. As of June 30, 2014, SWEPCo has incurred $72 million in costs related to these projects. SWEPCo will seek to recover these project costs from customers through filings at the state commissions and FERC. These environmental projects could be impacted

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by pending carbon emission regulations.  See "CO2 Regulation"  section of “Environmental Issues” below.  As of June 30, 2014, the net book value of Welsh Plant, Units 1 and 3 was $297 million, before cost of removal, including materials and supplies inventory and CWIP.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 

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 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, 2014, I&M has incurred costs of $439 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items which the IURC stated I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC. In May 2014, the IURC issued a final order approving the LCM rider rates that were implemented in January 2014.

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

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition. See “Cook Plant Life Cycle Management Project (LCM Project)” section of Note 4.

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 4 - Rate Matters, Note 6 - Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2013 Annual Report. Additionally, see Note 4 - Rate Matters and Note 5 - 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.

Rockport Plant Litigation

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

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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 2013 Annual Report. We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If we are unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System. We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of June 30, 2014, 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 generating facilities. Based upon our estimates, investment to meet these requirements ranges from approximately $3 billion to $3.5 billion through 2020. Several proposed regulations issued during 2014, including CO2 and Clean Water Act, are currently under review and we cannot currently predict the impact these programs may have on future resource plans or our existing generating fleet; however, the costs may be substantial. These amounts include investments to convert some of our coal generation 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 (SIPs) or federal implementation plans (FIPs) that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on our units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors. In addition, we are continuing to evaluate the economic feasibility of environmental investments on nonregulated plants.


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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
CompanyPlant Name and UnitCapacity
(in MWs) 
AGRKammer Plant630
AGRMuskingum River Plant1,440
AGRPicway Plant100
APCoClinch River Plant, Unit 3235
APCoGlen Lyn Plant335
APCoKanawha River Plant400
APCo/AGRSporn Plant600
I&MTanners Creek Plant995
KPCoBig Sandy Plant, Unit 2800
PSONortheastern Station, Unit 4470
SWEPCoWelsh Plant, Unit 2528
Total6,533

As of June 30, 2014, the net book value of the AGR units listed above was zero. The net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the regulated plants in the table above was $985 million.

In addition, we are in the process of obtaining permits and other necessary regulatory approvals for the conversion of KPCo's 278 MW Big Sandy Plant, Unit 1 to natural gas.  As of June 30, 2014, the net book value before cost of removal, including related material and supplies inventory and CWIP balances, of Big Sandy Plant, Unit 1 was $99 million.

PSO received Federal EPA approval of the Oklahoma SIP, in February 2014, related to the environmental compliance plan for Northeastern Station, Unit 3.

Volatility in fuel 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.

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 the Clean Air Interstate Rule (CAIR) in 2005 requiring specific reductions in SO2 and NOx emissions from power plants. The Federal EPA issued the Cross-State Air Pollution Rule (CSAPR) in August 2011 to replace CAIR. The CSAPR was challenged in the courts. The U.S. Court of Appeals for the District of Columbia Circuit issued an order in 2011 staying the effective date of the rule pending judicial review. In 2012, a panel of the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing CAIR until a replacement rule is finalized. That decision was appealed to the U.S. Supreme Court, which reversed the decision in part and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit. Nearly all of the states in which our power plants are located are covered by CAIR. See "Cross-State Air Pollution Rule (CSAPR)" section below.

The Federal EPA issued the final maximum achievable control technology (MACT) standards for coal and oil-fired power plants in 2012. See “Mercury and Other Hazardous Air Pollutants (HAPs) Regulation” section below.

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The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas. BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. CAVR will be implemented through individual SIPs or, if SIPs are not adequate or are not developed on schedule, through FIPs. The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas. 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 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.

In 2009, the Federal EPA issued a final mandatory reporting rule for CO2 and other greenhouse gases covering a broad range of facilities emitting in excess of 25,000 tons of CO2 emissions per year. The Federal EPA issued a final endangerment finding for greenhouse gas emissions from new motor vehicles in 2009. The Federal EPA determined that greenhouse gasemissions from stationary sources will be subject to regulation under the CAA beginning January 2011 and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, SIP calls and FIPs. The Federal EPA has proposed to include CO2 emissions in standards that apply to new electric utility units and will consider whether such standards are appropriate for other source categories in the future. See "CO2 Regulation" section below.

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

Notable developments in significant CAA regulatory requirements affecting our operations are discussed in the following sections.

Cross-State Air Pollution Rule (CSAPR)

In 2011, the Federal EPA issued CSAPR. Certain revisions to the rule were finalized in 2012. CSAPR relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states. Interstate trading of allowances is allowed on a restricted sub-regional basis. Arkansas and Louisiana are subject only to the seasonal NOx program in the rule. Texas is subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program. The annual SO2 allowance budgets in Indiana, Ohio and West Virginia were reduced significantly in the 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 2011, the court granted the motions for stay. In 2012, the court issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the CAIR 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

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was granted in June 2013. In April 2014, the U.S. Supreme Court issued a decision reversing in part the decision of the U.S. Court of Appeals for the District of Columbia Circuit and remanding the case for further proceedings consistent with the opinion. The parties have filed motions to govern further proceedings. The Federal EPA has filed a motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. Until the court acts on this motion, CAIR will remain in effect. Separate appeals of the Error Corrections Rule and the further revisions have been filed but no briefing schedules have been established. We cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In 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 several nonmercury metals) 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. Petitions for administrative reconsideration and judicial review were 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. The Federal EPA issued revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions in March 2013. The Federal EPA is still considering additional changes to the start-up and shut down provisions. In April 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the April 2012 final rule.

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. We have obtained a one-year administrative extension at several units to facilitate 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 remain concerned about the availability of compliance extensions, the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines and the lack of coordination among the Mercury and Air Toxics Standards schedule and other environmental requirements.

CO2 Regulation

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. The new proposal was issued in September 2013 and requires new large natural gas units to meet 1,000 pounds of CO2 per MWh of electricity generated and small natural gas units to meet 1,100 pounds of CO2 per MWh. New coal-fired units are required to meet the 1,100 pounds of CO2 per MWh limit, with the option to meet the tighter limits if they choose to average emissions over multiple years. The proposal was published in the Federal Register in January 2014.

The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from modified and reconstructed electric generating units (EGUs) and to issue guidelines for existing EGUs before June 2014, to finalize those standards by June 2015 and to require states to submit revisions to their implementation plans including such standards no later than June 2016. The President directed the Federal EPA, in developing this proposal, to directly engage states, leaders in the power sector, labor leaders and other stakeholders, to tailor the regulations to reduce costs, to develop market-based instruments and allow regulatory flexibilities and “assure that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power.” The Federal EPA issued proposed guidelines establishing state goals for CO2 emissions from existing EGUs and proposed regulations governing emissions of CO2 from modified and reconstructed EGUs in June 2014 and comments are due in October 2014. The guidelines use a “portfolio” approach to reducing emissions from existing sources that includes

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efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units, expanding renewable resources and increasing customer energy efficiency. The standards for modified and reconstructed units include several options, including use of historic baselines or energy efficiency audits to establish source-specific CO2 emission rates or to limit CO2 emissions to no more than 1,900 pounds per MWh at larger coal units and 2,100 pounds per MWh at smaller coal units. These proposed regulations are currently under review. 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 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. In 2012, the U.S. Court of Appeals for the District of Columbia Circuit denied a petition for rehearing. In June 2014, the U.S. Supreme Court determined that the Federal EPA was not compelled to regulate CO2 emissions from stationary sources under the Title V or PSD programs as a result of its adoption of the motor vehicle standards, but that sources otherwise required to obtain a PSD permit may be required to perform a Best Available Control Technology analysis for CO2 emissions if they exceed a reasonable level. The Federal EPA must undertake additional rulemaking to implement the court’s decision and establish an appropriate level.

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 and also FGD gypsum generated at some coal fired plants.  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 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. In 2013, the Federal EPA also issued a notice of data availability requesting comments on a narrow set of issues.

Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule. The Federal EPA opposed the petition and sought additional time to coordinate the issuance of a final rule with the issuance of new effluent limitations under the Clean Water Act (CWA) for utility facilities. In October 2013, the U.S. District Court for the District of Columbia issued a final order partially ruling in favor of the Federal EPA for dismissal of two counts, ruling in favor of the environmental organizations on one count and directing the Federal EPA to provide the court with a proposed schedule for completion of the rulemaking.  The court established December 19, 2014 as the Federal EPA’s deadline for publication of the rule. 

In February 2014, the Federal EPA completed a risk evaluation of the beneficial uses of coal fly ash in concrete and FGD gypsum in wallboard and concluded that the Federal EPA supports these beneficial uses.  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. We will incur significant costs to upgrade or close and replace these existing facilities under the proposed solid waste management alternative. Regulation of these materials as hazardous wastes would significantly increase these costs. As the rule is not final, we are unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.


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Clean Water Act Regulations

In 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. In 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments. The final rule was released by the Federal EPA in May 2014 and affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to comply with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures at facilities withdrawing more than 125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, are not expected to require any technology changes. Facilities subject to both the impingement standard and site-specific entrainment studies will typically be given at least three years to conduct and submit the results of those studies to the permit agency. Compliance timeframes will then be established by the permit agency through each facility’s National Pollutant Discharge Elimination System (NPDES) permit for installation of any required technology changes, as those permits are renewed over the next five to eight years.

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 September 2015. 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 continue to review the proposal in detail to evaluate whether our plants are currently meeting the proposed limitations, what technologies have been incorporated into our long-range plans and what additional costs might be incurred if the Federal EPA's most stringent options were adopted. We submitted detailed comments to the Federal EPA in September 2013 and participated in comments filed by various organizations of which we are members.

In April 2014, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a proposed rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases and published the proposed rule in the Federal Register. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This proposed jurisdictional definition will apply to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are: permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. We agree that clarity and efficiency in the permitting process is needed. We are concerned that the proposed rule introduces new concepts and could subject more of our operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. We will continue to evaluate the rule and its financial impact on the AEP System. We plan to submit comments and also participate in the preparation of comments to be filed by various organizations of which we are members.

Climate Change

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

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.

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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.

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 2013 Form 10-K under the headings entitled “Environmental and Other Matters” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

RESULTS OF OPERATIONS

SEGMENTS

Our primary business is the generation, transmission and distribution of electricity. Within our Vertically Integrated Utilities 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.

During the fourth quarter of 2013, we changed the structure of our internal organization which resulted in a change in the composition of our reportable segments. In accordance with authoritative accounting guidance for segment reporting, prior period financial information has been recast in the financial statements and footnotes to be comparable to the current year presentation of reportable segments.

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

Vertically Integrated Utilities

·Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.
Generation, transmission and distributionof electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

·
Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
·OPCo purchases energy to serve standard service offer
Transmission and distributionof electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
OPCo purchases energy to serve SSO customers and provides capacity for all connected load.

AEP Transmission Holdco

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

Generation & Marketing

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


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AEP River Operations

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

The table below presents Net Income (Loss) by segment for the three and six months ended March 31,June 30, 2014 and 2013.

  Three Months Ended March 31,
  2014  2013 
  (in millions)
Vertically Integrated Utilities$ 279  $ 181 
Transmission and Distribution Utilities  97    87 
AEP Transmission Holdco  24    12 
Generation & Marketing  163    85 
AEP River Operations  3    (2)
Corporate and Other (a)  (5)   1 
Net Income$ 561  $ 364 
      
(a)  While not considered a reportable segment, Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries.  This segment also includes parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
 Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
 2014 2013 2014 2013
 (in millions)
Vertically Integrated Utilities$155
 $153
 $434
 $334
Transmission and Distribution Utilities90
 75
 187
 162
AEP Transmission Holdco47
 19
 71
 31
Generation & Marketing98
 (9) 261
 76
AEP River Operations3
 (9) 6
 (11)
Corporate and Other (a)(2) 110
 (7) 111
Net Income$391
 $339
 $952
 $703
(a)While not considered a reportable segment, Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. The segment also includes parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
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AEP CONSOLIDATED

FirstSecond Quarter of 2014 Compared to FirstSecond Quarter of 2013

Net Income increased from $364$339 million in 2013 to $561$391 million in 2014 primarily due to:

·Successful rate proceedings in our various jurisdictions.
·An increase in weather-related usage.
·Higher market prices and increased sales volumes.
Successful rate proceedings in our various jurisdictions.
An increase in transmission investment which resulted in higher revenues and income.
Higher market prices.
The second quarter 2013 impairment of Muskingum River Plant, Unit 5.

These increases were partially offset by:

A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Net Income increased from $703 million in 2013 to $952 million in 2014 primarily due to:

Successful rate proceedings in our various jurisdictions.
An increase in transmission investment which resulted in higher revenues and income.
Higher market prices and increased sales volumes.
An increase in weather-related usage.
The second quarter 2013 impairment of Muskingum River Plant, Unit 5.

These increases were partially offset by:

A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.

Our results of operations are discussed below by operating segment.

13



VERTICALLY INTEGRATED UTILITIES

  Three Months Ended 
  March 31,  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
Vertically Integrated UtilitiesVertically Integrated Utilities 2014  2013   2014 2013 2014 2013
  (in millions)  (in millions)
RevenuesRevenues $ 2,586  $ 2,515   $2,252
 $2,302
 $4,838
 $4,817
Fuel and Purchased ElectricityFuel and Purchased Electricity   1,094    1,201   934
 1,064
 2,028
 2,265
Gross MarginGross Margin   1,492   1,314   1,318
 1,238
 2,810
 2,552
Other Operation and MaintenanceOther Operation and Maintenance  576   578   618
 551
 1,194
 1,129
Depreciation and AmortizationDepreciation and Amortization  263   235   252
 234
 515
 469
Taxes Other Than Income TaxesTaxes Other Than Income Taxes   96    91   87
 93
 183
 184
Operating IncomeOperating Income   557   410   361
 360
 918
 770
Interest and Investment IncomeInterest and Investment Income  1   3   —
 4
 1
 7
Carrying Costs Income (Expense)  (1)  1  
Carrying Costs Income 2
 4
 1
 5
Allowance for Equity Funds Used During ConstructionAllowance for Equity Funds Used During Construction  10   9   11
 9
 21
 18
Interest ExpenseInterest Expense   (131)   (136)  (132) (136) (263) (272)
Income Before Income Tax Expense   436   287  
Income Before Income Tax Expense and Equity Earnings 242
 241
 678
 528
Income Tax ExpenseIncome Tax Expense   157    106   88
 89
 245
 195
Equity Earnings of Unconsolidated Subsidiaries 1
 1
 1
 1
Net IncomeNet Income $ 279  $ 181   $155
 $153
 $434
 $334

Summary of KWh Energy Sales for Vertically Integrated Utilities 
  
    Three Months Ended March 31, 
 2014  2013  
    (in millions of KWhs) 
Retail:      
 Residential  10,905    9,789  
 Commercial  6,115    5,845  
 Industrial  8,332    8,261  
 Miscellaneous  555    549  
Total Retail  25,907    24,444  
       
Wholesale (a)  10,184   NM (b) 
       
(a)Includes Off-system Sales, Municipalities and Cooperatives, Unit Power and Other Wholesale Customers. 
(b)2014 is not comparable to 2013 due to the 2013 asset transfers related to corporate separation as well as the termination of the pool agreement on December 31, 2013. 
NMNot meaningful. 
Summary of KWh Energy Sales for Vertically Integrated Utilities
 Three Months Ended 
 June 30,		  Six Months Ended 
 June 30,		 
 2014 2013  2014 2013 
 (in millions of KWhs) 
Retail: 
  
   
  
 
Residential6,716
 6,878
  17,621
 16,667
 
Commercial6,122
 6,158
  12,237
 12,003
 
Industrial9,025
 8,707
  17,357
 16,968
 
Miscellaneous577
 566
  1,132
 1,115
 
Total Retail22,440
 22,309
  48,347
 46,753
 
          
Wholesale (a)8,602
 NM
(b) 18,786
 NM
(b)

(a)Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers.
(b)2014 is not comparable to 2013 due to the 2013 asset transfers related to corporate separation in Ohio on December 31, 2013 and the termination of the Interconnection Agreement effective January 1, 2014.
NMNot meaningful.


14
12


Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.revenues.  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 Vertically Integrated Utilities
 
  Three Months Ended March 31,
  2014  2013 
  (in degree days)
      
Eastern Region     
Actual - Heating (a)  2,128    1,705 
Normal - Heating (b)  1,593    1,595 
       
Actual - Cooling (c)  -    - 
Normal - Cooling (b)  5    5 
       
Western Region     
Actual - Heating (a)  1,186    915 
Normal - Heating (b)  887    890 
       
Actual - Cooling (c)  6    10 
Normal - Cooling (b)  24    24 
       
(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 and Western Region cooling degree days are calculated on a 65 degree temperature base.
Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
 Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
 2014 2013 2014 2013
 (in degree days)
Eastern Region 
  
  
  
Actual - Heating (a)118
 148
 2,246
 1,853
Normal - Heating (b)138
 140
 1,731
 1,735
        
Actual - Cooling (c)362
 350
 362
 350
Normal - Cooling (b)324
 324
 329
 329
        
Western Region 
  
  
  
Actual - Heating (a)47
 94
 1,233
 1,009
Normal - Heating (b)33
 31
 920
 921
        
Actual - Cooling (c)674
 673
 680
 683
Normal - Cooling (b)686
 686
 710
 710

(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 and Western Region cooling degree days are calculated on a 65 degree temperature base.


15
13


FirstSecond Quarter of 2014 Compared to FirstSecond Quarter of 2013
Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income from Vertically Integrated Utilities
(in millions)
First Quarter of 2013$ 181 
Changes in Gross Margin:
Retail Margins 90 
Off-system Sales 85 
Transmission Revenues 10 
Other Revenues (7)
Total Change in Gross Margin 178 
Changes in Expenses and Other:
Other Operation and Maintenance 2 
Depreciation and Amortization (28)
Taxes Other Than Income Taxes (5)
Interest and Investment Income (2)
Carrying Costs Income (2)
Allowance for Equity Funds Used During Construction 1 
Interest Expense 5 
Total Change in Expenses and Other (29)
Income Tax Expense (51)
First Quarter of 2014$ 279 
Reconciliation of Second Quarter of 2013 to Second Quarter of 2014
Net Income from Vertically Integrated Utilities
(in millions)
   
Second Quarter of 2013 $153
   
Changes in Gross Margin:  
Retail Margins 61
Off-system Sales 21
Transmission Revenues 6
Other Revenues (8)
Total Change in Gross Margin 80
   
Changes in Expenses and Other:  
Other Operation and Maintenance (67)
Depreciation and Amortization (18)
Taxes Other Than Income Taxes 6
Interest and Investment Income (4)
Carrying Costs Income (2)
Allowance for Equity Funds Used During Construction 2
Interest Expense 4
Total Change in Expenses and Other (79)
   
Income Tax Expense 1
   
Second Quarter of 2014 $155

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 $90 million primarily due to the following:
·Successful rate proceedings in our service territories which include:
·A $26 million increase primarily due to changes in rates in West Virginia.
·A $24 million rate increase for SWEPCo.
·A $22 million rate increase for I&M.
·A $13 million rate increase for KPCo.
For the rate increases described above, $26 million relates to riders/trackers which have corresponding increases in other expense items below.
·A $55 million increase in weather-related usage in our eastern and western regions primarily due to increases of 25% and 30%, respectively, in heating degree days.
These increases were partially offset by:
·A $42 million increase in PJM expenses net of recovery or offsets.
·
Margins from Off-system Sales increased $85 million primarily due to higher market prices.
·
Transmission Revenues increased $10 million primarily due to increased investment in the PJM and SPP regions.  These increased revenues are partially
Retail Margins increased $61 million primarily due to the following:
The effect of successful rate proceedings in our service territories which include:
APCo - $46 million.
SWEPCo - $21 million.
For the rate increases described above, $26 million of these increases relate to riders/trackers which have corresponding increases in expense items below.    
Margins from Off-system Sales increased $21 million primarily due to higher market prices and increased sales volumes.
Transmission Revenues increased $6 million primarily due to increased investment in the PJM region.
Other Revenues decreased $8 million primarily due to a decrease in barging. This decrease in barging is a result of the River Transportation Division (RTD) no longer serving plants transferred from OPCo to AGR at December 31, 2013 as a result of corporate separation. The decrease in RTD revenue was offset by a corresponding decrease in Other Operation and Maintenance expenses for barging as discussed below.
·
Other Revenues decreased $7 million primarily due to a decrease in barging.  This decrease in barging is a result of the River Transportation Division (RTD) no longer serving Ohio plants transferred to AGR as a result of corporate separation.  The decrease in RTD revenue was offset by a decrease in Other Operation and Maintenance expenses for barging.


16
14


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

·
Other Operation and Maintenance expenses decreased $2 million primarily due to the following:
·A $30 million write-off in 2013 of previously deferred Virginia storm costs resulting from the 2013 enactment of a Virginia law.
·A $12 million decrease in storm-related expenses primarily in APCo's service territory.
These decreases were partially offset by:
·A $25 million increase due to a favorable settlement of an insurance claim in the first quarter of 2013.
·A $17 million increase in PJM and other transmission expenses.
·
Depreciation and Amortization expenses increased $28 million primarily due to overall higher depreciable property balances.
·
Interest Expense decreased $5 million primarily due to a decrease in interest on long-term debt.
·
Income Tax Expense increased $51
Other Operation and Maintenance expenses increased $67 million primarily due to the following:
A $31 million increase in transmission expenses primarily related to PJM and SPP services.
A $23 million increase in plant outage and maintenance expenses.
A $14 million increase in recoverable PJM and other expenses currently fully recovered in rate recovery riders/trackers.
A $6 million increase in distribution expenses related to various distribution services and forestry expenses.
These increases were partially offset by:
A $9 million decrease in storm-related expenses primarily in APCo's service territory.
A $9 million decrease in RTD expenses for barging activities. The decrease in RTD expenses was offset by a decrease in Retail Margins discussed above.
Depreciation and Amortization expenses increased $18 millionprimarily due to overall higher depreciable base.

17


Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013
Reconciliation of Six Months Ended June 30, 2013 to Six Months Ended June 30, 2014
Net Income from Vertically Integrated Utilities
(in millions)
   
Six Months Ended June 30, 2013 $334
   
Changes in Gross Margin:  
Retail Margins 163
Off-system Sales 106
Transmission Revenues 16
Other Revenues (27)
Total Change in Gross Margin 258
   
Changes in Expenses and Other:  
Other Operation and Maintenance (65)
Depreciation and Amortization (46)
Taxes Other Than Income Taxes 1
Interest and Investment Income (6)
Carrying Costs Income (4)
Allowance for Equity Funds Used During Construction 3
Interest Expense 9
Total Change in Expenses and Other (108)
   
Income Tax Expense (50)
   
Six Months Ended June 30, 2014 $434

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 $163 million primarily due to the following:
The effect of successful rate proceedings in our service territories which include:
APCo - $72 million.
SWEPCo - $45 million.
KPCo - $26 million.
I&M - $11 million.
For the rate increases described above, $50 million of these increases relate to riders/trackers which have corresponding increases in expense items below.
A $52 million increase due to favorable weather conditions.
These increases were partially offset by:
A $40 million increase in PJM expenses net of recovery or offsets.
Margins from Off-system Sales increased $106 million primarily due to higher market prices and increased sales volumes.
Transmission Revenues increased $16 million primarily due to increased investment in the PJM region.
Other Revenues decreased $27 million primarily due to a decrease in barging. This decrease in barging is a result of the RTD no longer serving plants transferred from OPCo to AGR at December 31, 2013 as a result of corporate separation. The decrease in RTD revenue was offset by a decrease in Other Operation and Maintenance expenses for barging as discussed below.


18


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

Other Operation and Maintenance expenses increased $65 million primarily due to the following:
A $48 million increase in transmission expenses primarily related to PJM and SPP services.
A $26 million increase in plant outage and maintenance expenses.
A $25 million increase due to an agreement reached to settle an insurance claim in the first quarter of 2013.
A $21 million increase in recoverable PJM and other expenses currently fully recovered in rate recovery riders/trackers.
A $12 million increase in distribution expenses related to various distribution services and forestry expenses.
These increases were partially offset by:
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 $23 million decrease in RTD expenses for barging activities. The decrease in RTD expenses was offset by a decrease in Retail Margins discussed above.
A $20 million decrease in storm-related expenses primarily in APCo's service territory.
Depreciation and Amortization expenses increased $46 million primarily due to overall higher depreciable base.
Interest Expense decreased $9 million primarily due to the following:
A $5 million decrease due to the retirement of KPCo Senior Unsecured Notes in the third quarter of 2013.
A $4 million decrease due to rate approvals in Louisiana and Texas and an increase in the debt component of AFUDC due to increased transmission and environmental projects.
Income Tax Expense increased $50 million primarily due to an increase in pretax book income.

TRANSMISSION AND DISTRIBUTION UTILITIES

  Three Months Ended 
  March 31,  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
Transmission and Distribution Utilities Transmission and Distribution Utilities  2014  2013   2014 2013 2014 2013
  (in millions)  (in millions)
RevenuesRevenues $ 1,215  $ 1,134   $1,134
 $1,064
 $2,349
 $2,198
Fuel and Purchased ElectricityFuel and Purchased Electricity  403   449   343
 405
 746
 854
Amortization of Generation DeferralsAmortization of Generation Deferrals   31    -   25
 —
 56
 —
Gross MarginGross Margin   781   685   766
 659
 1,547
 1,344
Other Operation and MaintenanceOther Operation and Maintenance  293   244   298
 219
 591
 463
Depreciation and AmortizationDepreciation and Amortization  161   133   156
 151
 317
 284
Taxes Other Than Income TaxesTaxes Other Than Income Taxes   119    104   108
 105
 227
 209
Operating IncomeOperating Income   208   204   204
 184
 412
 388
Interest and Investment IncomeInterest and Investment Income  3   1   3
 —
 6
 1
Carrying Costs IncomeCarrying Costs Income  7   3   7
 4
 14
 7
Allowance for Equity Funds Used During ConstructionAllowance for Equity Funds Used During Construction  3   2   2
 —
 5
 2
Interest ExpenseInterest Expense   (70)   (75)  (72) (72) (142) (147)
Income Before Income Tax ExpenseIncome Before Income Tax Expense   151   135   144
 116
 295
 251
Income Tax ExpenseIncome Tax Expense   54    48   54
 41
 108
 89
Net IncomeNet Income $ 97  $ 87   $90
 $75
 $187
 $162


Summary of KWh Energy Sales for Transmission and Distribution Utilities 
  
    Three Months Ended March 31, 
 2014  2013  
Retail:      
 Residential  7,527    6,466  
 Commercial  5,902    5,706  
 Industrial  5,143    5,500  
 Miscellaneous  171    160  
Total Retail (a)  18,743    17,832  
       
Wholesale (b)  700   NM (c) 
       
(a)Represents energy delivered to distribution customers. 
(b)Includes Off-system Sales, Municipalities and Cooperatives, Unit Power and Other Wholesale Customers. 
(c)2014 is not comparable to 2013 due to the 2013 asset transfers related to corporate separation as well as the termination of the pool agreement on December 31, 2013. 
NMNot meaningful. 
19


Summary of KWh Energy Sales for Transmission and Distribution Utilities
 Three Months Ended 
 June 30,		  Six Months Ended 
 June 30,		 
 2014 2013  2014 2013 
 (in millions of KWhs) 
Retail: 
  
   
  
 
Residential5,559
 5,752
  13,086
 12,218
 
Commercial6,314
 6,394
  12,216
 12,100
 
Industrial5,630
 5,895
  10,773
 11,395
 
Miscellaneous182
 180
  353
 340
 
Total Retail (a)17,685
 18,221
  36,428
 36,053
 
          
Wholesale (b)453
 NM
(c) 1,152
 NM
(c)

(a)Represents energy delivered to distribution customers.
(b)Ohio's contractually obligated purchases of OVEC power sold into PJM.
(c)2014 is not comparable to 2013 due to the 2013 asset transfers related to corporate separation in Ohio on December 31, 2013 and the termination of the Interconnection Agreement effective January 1, 2014.
NMNot meaningful.
15

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.revenues.  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 Transmission and Distribution Utilities 
  
  Three Months Ended March 31, 
  2014  2013  
  (in degree days) 
       
Eastern Region      
Actual - Heating (a)  2,409    1,971  
Normal - Heating (b)  1,880    1,885  
        
Actual - Cooling (c)  -    -  
Normal - Cooling (b)  3    3  
        
Western Region      
Actual - Heating (a)  300    135  
Normal - Heating (b)  196    201  
        
Actual - Cooling (d)  70    137  
Normal - Cooling (b)  108    105  
        
(a)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 70 degree temperature base. 
Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
 Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
 2014 2013 2014 2013
 (in degree days)
Eastern Region 
  
  
  
Actual - Heating (a)130
 193
 2,539
 2,164
Normal - Heating (b)187
 190
 2,067
 2,075
        
Actual - Cooling (c)362
 346
 362
 346
Normal - Cooling (b)280
 277
 283
 280
        
Western Region 
  
  
  
Actual - Heating (a)2
 8
 302
 143
Normal - Heating (b)4
 4
 200
 205
        
Actual - Cooling (d)872
 940
 942
 1,077
Normal - Cooling (b)904
 902
 1,012
 1,007

(a)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 70 degree temperature base.


20
16


FirstSecond Quarter of 2014 Compared to FirstSecond Quarter of 2013
Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income from Transmission and Distribution Utilities
(in millions)
First Quarter of 2013$ 87 
Changes in Gross Margin:
Retail Margins 73 
Transmission Revenues 14 
Other Revenues 9 
Total Change in Gross Margin 96 
Changes in Expenses and Other:
Other Operation and Maintenance (49)
Depreciation and Amortization (28)
Taxes Other Than Income Taxes (15)
Interest and Investment Income 2 
Carrying Costs Income 4 
Allowance for Equity Funds Used During Construction 1 
Interest Expense 5 
Total Change in Expenses and Other (80)
Income Tax Expense (6)
First Quarter of 2014$ 97 
Reconciliation of Second Quarter of 2013 to Second Quarter of 2014
Net Income from Transmission and Distribution Utilities
(in millions)
   
Second Quarter of 2013 $75
   
Changes in Gross Margin:  
Retail Margins 74
Transmission Revenues 33
Total Change in Gross Margin 107
   
Changes in Expenses and Other:  
Other Operation and Maintenance (79)
Depreciation and Amortization (5)
Taxes Other Than Income Taxes (3)
Interest and Investment Income 3
Carrying Costs Income 3
Allowance for Equity Funds Used During Construction 2
Total Change in Expenses and Other (79)
   
Income Tax Expense (13)
   
Second Quarter of 2014 $90

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:

·
Retail Margins increased $73
Retail Margins increased $74 million primarily due to the following:
A $33 million increase in PJM revenues that are offset in expense items discussed below.
A $19 million increase for TCC and TNC primarily due to favorable prices.
A $14 million increase in OPCo revenues primarily associated with the Distribution Investment Rider (DIR) and Universal Service Fund (USF) surcharge. Of these increases, $2 million relate to riders/trackers which have corresponding increases in other expense items below.
A $13 million increase in OPCo revenues associated with the Storm Damage Recovery Rider implemented in April 2014. This increase in Retail Margins is offset by an increase in expense items discussed below.
Transmission Revenues increased $33 million primarily due to increased transmission investment, increased transmission revenues from customers who have switched to alternative CRES providers and rate increases for customers in the PJM region.  The increase in transmission revenues related to CRES providers primarily offsets lost revenues included in Retail Margins above.
·A $29 million increase for TCC and TNC primarily due to a 325% and 39% increase in heating degree days, respectively.
·An $17 million increase primarily due to increased connected load for OPCo and corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
·A $15 million increase in revenues associated with the Distribution Investment Recovery Rider and Universal Service Fund (USF) surcharge.  Of these increases, $10 million relate to riders/trackers which have corresponding increases in other expense items below.
·
Transmission Revenues increased $14 million primarily due to increased transmission revenues from Ohio customers who switched to alternative CRES providers and rate increases for customers in the PJM region.
·
Other Revenues increased $9 million primarily due to increased Texas securitization revenues.


21


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

·
Other Operation and Maintenance expenses increased $49 million primarily due to the following:
·A $27 million increase primarily due to PJM and ERCOT expenses.  This increase is offset by an increase in Retail Margins above.
·An $8 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 is offset by an increase in Retail Margins above.
·An $8 million increase in distribution expenses.
·A $5 million increase in storm-related expenses primarily in OPCo's service territory.
·
Depreciation and Amortization expenses increased $28 million primarily related to the following:
·A $19 million increase in amortization related to TCC and OPCo securitizations.
·
A $4 million increase for OPCo due to carrying charge adjustments as a result of expensing certain gridSMART® capital projects.
·A $3 million increase due to an increase in depreciable base of transmission and distribution assets.
·
Taxes Other Than Income Taxes increased $15 million primarily due to increased property taxes.
·
Income Tax Expense increased $6 million primarily due to an increase in pretax book income.
Other Operation and Maintenance expenses increased $79 million primarily due to the following:
A $55 million increase in recoverable PJM and other expenses currently fully recovered in rate recovery riders/trackers.
A $12 million increase in transmission expenses primarily related to PJM services.
A $5 million increase in distribution expenses related to various distribution services and programs.
A $3 million increase in storm-related expenses primarily in OPCo's service territory.    
Depreciation and Amortization expenses increased $5 millionprimarily due to the following:
A $3 million increase in amortization related to TCC and OPCo securitizations, which are offset in Retail Margins above.
A $3 million increase due to an increase in the depreciable base of transmission and distribution assets.
Income Tax Expense increased $13 million primarily due to an increase in pretax book income.


22


Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013
Reconciliation of Six Months Ended June 30, 2013 to Six Months Ended June 30, 2014
Net Income from Transmission and Distribution Utilities
(in millions)
   
Six Months Ended June 30, 2013 $162
   
Changes in Gross Margin:  
Retail Margins 147
Transmission Revenues 47
Other Revenues 9
Total Change in Gross Margin 203
   
Changes in Expenses and Other:  
Other Operation and Maintenance (128)
Depreciation and Amortization (33)
Taxes Other Than Income Taxes (18)
Interest and Investment Income 5
Carrying Costs Income 7
Allowance for Equity Funds Used During Construction 3
Interest Expense 5
Total Change in Expenses and Other (159)
   
Income Tax Expense (19)
   
Six Months Ended June 30, 2014 $187

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:

Retail Margins increased $147 million primarily due to the following:
A $48 million increase for TCC and TNC primarily due to favorable prices and increased usage.
A $28 million increase in OPCo revenues primarily associated with the DIR and USF surcharge. Of these increases, $12 million relate to riders/trackers which have corresponding increases in other expense items below.
A $21 million increase in PJM revenues that are offset in expense items discussed below.
A $17 million increase primarily due to increased connected load for OPCo.
A $13 million increase in OPCo revenues associated with the Storm Damage Recovery Rider. This increase in Retail Margins is offset by an increase in expense items discussed below.
Transmission Revenues increased $47 million primarily due to increased transmission investment, increased transmission revenues from customers who have switched to alternative CRES providers and rate increases for customers in the PJM region.  The increase in transmission revenues related to CRES providers primarily offsets lost revenues included in Retail Margins above.
17Other Revenues increased $9 million primarily due to increased Texas securitization revenues.


23


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

Other Operation and Maintenance expenses increased $128 million primarily due to the following:
An $80 million increase in recoverable PJM and other expenses currently fully recovered in rate recovery riders/trackers.
A $13 million increase in expenses related to various distribution services and programs.
An $11 million increase in transmission expenses primarily related to PJM and forestry expenses.
A $10 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 an increase in Retail Margins above.
A $9 million increase in storm-related expenses primarily in OPCo's service territory.
Depreciation and Amortization expenses increased $33 million primarily due to the following:
A $22 million increase in amortization related to TCC and OPCo securitizations, which are offset in Retail Margins.
A $6 million increase due to an increase in the depreciable base of transmission and distribution assets.
Taxes Other Than Income Taxes increased $18 million primarily due to increased property taxes.
Income Tax Expense increased $19 million primarily due to an increase in pretax book income.


24


AEP TRANSMISSION HOLDCO

FirstSecond Quarter of 2014 Compared to FirstSecond Quarter of 2013

Net Income from our AEP Transmission Holdco segment increased from $12$19 million in 2013 to $24$47 million in 2014 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Net Income from our AEP Transmission Holdco segment increased from $31 million in 2013 to $71 million in 2014 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT.

GENERATION & MARKETING

  Three Months Ended 
  March 31, 
Generation & Marketing 2014  2013   Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
Generation & Marketing 2014 2013 2014 2013
  (in millions)  (in millions)
RevenuesRevenues $ 1,251  $ 920   $913
 $892
 $2,164
 $1,812
Fuel, Purchased Electricity and OtherFuel, Purchased Electricity and Other   805    568   560
 548
 1,365
 1,116
Gross MarginGross Margin   446   352   353
 344
 799
 696
Other Operation and MaintenanceOther Operation and Maintenance  116   124   125
 112
 241
 236
Asset Impairments and Other Related Charges —
 154
 —
 154
Depreciation and AmortizationDepreciation and Amortization  57   62   56
 61
 113
 123
Taxes Other Than Income TaxesTaxes Other Than Income Taxes   12    16   13
 17
 25
 33
Operating IncomeOperating Income   261   150   159
 —
 420
 150
Interest and Investment IncomeInterest and Investment Income  1   -   1
 2
 2
 2
Interest ExpenseInterest Expense   (12)   (19)  (11) (15) (23) (34)
Income Before Income Tax Expense   250   131  
Income Tax Expense   87    46  
Net Income $ 163  $ 85  
Income (Loss) Before Income Tax Expense (Credit) 149
 (13) 399
 118
Income Tax Expense (Credit) 51
 (4) 138
 42
Net Income (Loss) $98
 $(9) $261
 $76

Summary of MWhs Generated for Generation & Marketing
 
  Three Months Ended March 31,
 2014  2013 
  (in millions of MWhs)
Fuel Type:     
 Coal  12    10 
 Natural Gas  2    2 
Total MWhs  14    12 
Summary of MWhs Generated for Generation & Marketing
 Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
 2014 2013 2014 2013
 (in millions of MWhs)
Fuel Type: 
  
  
  
Coal9
 9
 21
 19
Natural Gas2
 1
 4
 3
Total MWhs11
 10
 25
 22


25
18


FirstSecond Quarter of 2014 Compared to FirstSecond Quarter of 2013
Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income from Generation & Marketing
(in millions)
First Quarter of 2013$ 85 
Changes in Gross Margin:
Generation 97 
Retail, Trading and Marketing (3)
Total Change in Gross Margin 94 
Changes in Expenses and Other:
Other Operation and Maintenance 8 
Depreciation and Amortization 5 
Taxes Other Than Income Taxes 4 
Interest and Investment Income 1 
Interest Expense 7 
Total Change in Expenses and Other 25 
Income Tax Expense (41)
First Quarter of 2014$ 163 
Reconciliation of Second Quarter of 2013 to Second Quarter of 2014
Net Income from Generation & Marketing
(in millions)
   
Second Quarter of 2013 $(9)
   
Changes in Gross Margin:  
Generation 5
Retail, Trading and Marketing 4
Total Change in Gross Margin 9
   
Changes in Expenses and Other:  
Other Operation and Maintenance (13)
Asset Impairments and Other Related Charges 154
Depreciation and Amortization 5
Taxes Other Than Income Taxes 4
Interest and Investment Income (1)
Interest Expense 4
Total Change in Expenses and Other 153
   
Income Tax Expense (55)
   
Second Quarter of 2014 $98

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 and certain costs of service for retail operations were as follows:

·
Generation
Gross Marginincreased $9 million primarily due to increased $94 million primarily due to increases in demand and market prices driven by cold temperatures in 2014.

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

·
Other Operation and Maintenance expenses decreased $8 million primarily due to a reduction in employee related expenses.
·
Depreciation and Amortization expenses decreased $5 million primarily due to the cessation of depreciation on Muskingum River Plant, Unit 5.
·
Interest Expense decreased $7 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·
Income Tax Expense increased $41
Other Operation and Maintenance expenses increased $13 million primarily due to increased plant maintenance expenses.
Asset Impairments and Other Related Charges decreased by $154 million primarily due to the 2013 impairment of Muskingum River Plant, Unit 5.
Depreciation and Amortization expenses decreased $5 million primarily due to the cessation of depreciation on Muskingum River Plant, Unit 5.
Income Tax Expense increased $55 million primarily due to an increase in pretax book income.


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Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013
Reconciliation of Six Months Ended June 30, 2013 to Six Months Ended June 30, 2014
Net Income from Generation & Marketing
(in millions)
   
Six Months Ended June 30, 2013 $76
   
Changes in Gross Margin:  
Generation 99
Retail, Trading and Marketing 4
Total Change in Gross Margin 103
   
Changes in Expenses and Other:  
Other Operation and Maintenance (5)
Asset Impairments and Other Related Charges 154
Depreciation and Amortization 10
Taxes Other Than Income Taxes 8
Interest Expense 11
Total Change in Expenses and Other 178
   
Income Tax Expense (96)
   
Six Months Ended June 30, 2014 $261

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:

Generation increased $99 million primarily due to increased demand and market prices driven by cold temperatures in the first quarter of 2014.

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

Other Operation and Maintenance expenses increased $5 million primarily due to increased plant maintenance expenses.
Asset Impairments and Other Related Charges decreased by $154 million primarily due to the 2013 impairment of Muskingum River Plant, Unit 5.
Depreciation and Amortization expenses decreased $10 million primarily due to the cessation of depreciation on Muskingum River Plant, Unit 5.
Taxes Other Than Income Taxes decreased $8 million primarily due to property taxes related to the 2012 and 2013 plant impairments.
Interest Expense decreased $11 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
Income Tax Expense increased $96 million primarily due to an increase in pretax book income.


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AEP RIVER OPERATIONS

FirstSecond Quarter of 2014 Compared to FirstSecond Quarter of 2013

Net Income from our AEP River Operations segment increased from a loss of $2$9 million in 2013 to income of $3 million in 2014 due to a 45% increase in barge freight revenue for the second quarter of 2014 compared to the second quarter of 2013. The increase in freight revenue is primarily due to improvements in barge freight demand.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Net Income from our AEP River Operations segment increased from a loss of $11 million in 2013 to income of $6 million in 2014 due to a 34% increase in barge freight revenue for 2014 compared to 2013. The additional revenue resulted from improvements in river conditions as well as improvements in grain exportand increased barge freight demand.

CORPORATE AND OTHER

FirstSecond Quarter of 2014 Compared to FirstSecond Quarter of 2013

Net Income from Corporate and Other decreased from income of $1$110 million in 2013 to a loss of $5$2 million in 2014 primarily due to an increasea favorable U.K. Windfall Tax decision by the U.S. Supreme Court in net interest.the second quarter of 2013.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013
19
Net Income from Corporate and Other decreased from income of $111 million in 2013 to a loss of $7 million in 2014 primarily due to a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.

AEP SYSTEM INCOME TAXES

FirstSecond Quarter of 2014 Compared to FirstSecond Quarter of 2013

Income Tax Expense increased $112$147 million primarily due to an increase in pretax book income.income and a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Income Tax Expense increased $259 million primarily due to an increase in pretax book income and a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.

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, 2014 December 31, 2013
 (dollars in millions)
Long-term Debt, including amounts due within one year$18,125
 50.1% $18,377
 52.2%
Short-term Debt1,482
 4.1
 757
 2.1
Total Debt19,607
 54.2
 19,134
 54.3
AEP Common Equity16,581
 45.8
 16,085
 45.7
Noncontrolling Interests4
 —
 1
 —
        
Total Debt and Equity Capitalization$36,192
 100.0% $35,220
 100.0%

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  March 31, 2014 December 31, 2013
  (dollars in millions)
Long-term Debt, including amounts due within one year$ 18,087   50.5 % $ 18,377   52.2 %
Short-term Debt  1,332   3.7     757   2.1  
Total Debt  19,419   54.2     19,134   54.3  
AEP Common Equity  16,416   45.8     16,085   45.7  
Noncontrolling Interests  3   -     1   -  
            
Total Debt and Equity Capitalization$ 35,838   100.0 % $ 35,220   100.0 %


Our ratio of debt-to-total capital declinedimproved from 54.3% as of December 31, 2013 to 54.2% as of March 31,June 30, 2014 primarily due to an increase in our common equity from earnings.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability.  We believe we have adequate liquidity under our existing credit facilities.  As of March 31,June 30, 2014, we had $3.5 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.

Commercial Paper Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  As of March 31,June 30, 2014, our available liquidity was approximately $3$2.9 billion as illustrated in the table below:

AmountMaturity
(in millions)
Commercial Paper Backup:
Revolving Credit Facility$ 1,750 June 2016
Revolving Credit Facility 1,750 July 2017
Total 3,500 
Cash and Cash Equivalents 292 
Total Liquidity Sources 3,792 
Less:AEP Commercial Paper Outstanding 632 
Letters of Credit Issued 130 
Net Available Liquidity$ 3,030 
  Amount Maturity
  (in millions)  
Commercial Paper Backup: 
  
 Revolving Credit Facility$1,750
 June 2016
 Revolving Credit Facility1,750
 July 2017
Total3,500
  
Cash and Cash Equivalents190
  
Total Liquidity Sources3,690
  
Less:AEP Commercial Paper Outstanding732
  
 Letters of Credit Issued49
  
     
Net Available Liquidity$2,909
  

20
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 threesix months of 2014 was $691$877 million.  The weighted-average interest rate for our commercial paper during 2014 was 0.28%0.26%.

Other Credit Facilities

In January 2014, we issued letters of credit under an $85 million uncommitted facility signed in October 2013. As of March 31,June 30, 2014, the maximum future payment for letters of credit issued under the uncommitted facility was $75$69 million with a maturity in July 2014.January 2015. An uncommitted facility gives the issuer of the facility the right to accept or decline each request we make under the facility.

Securitized Accounts Receivable

Our receivables securitization agreement provides a commitment of $700$750 million from bank conduits to purchase receivables. A commitment of $385The agreement was increased from $700 million and expires in June 2014.  The remaining commitment of $315 million expires in June 2015.  We intend to extend or replace the agreement expiring in June 2014 on or before its maturity.2016.


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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 credit agreements. Debt as defined in the revolving credit agreements excludes securitization bonds and debt of AEP Credit. As of March 31,June 30, 2014,this contractually-defined percentage was 50.6%50.4%. Nonperformance under these covenants could result in an event of default under these credit agreements. As of March 31,June 30, 2014, 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. This condition also applies in a majority of our non-exchange traded commodity contracts and would similarly allow 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 credit agreements.

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

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders. As of March 31,June 30, 2014, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.50 per share in AprilJuly 2014. 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 primarily 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.

21
Credit Ratings

We do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but our access to the commercial paper market may depend on our credit ratings.  In addition, downgrades in our credit ratings by one of the rating agencies could increase our borrowing costs.  Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject us to additional collateral demands under adequate assurance clauses under our derivative and non-derivative energy contracts.

CASH FLOW

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

  Three Months Ended
  March 31,Six Months Ended 
 June 30,
  2014  2013 2014 2013
  (in millions)(in millions)
Cash and Cash Equivalents at Beginning of PeriodCash and Cash Equivalents at Beginning of Period $ 118  $ 279 $118
 $279
Net Cash Flows from Operating ActivitiesNet Cash Flows from Operating Activities  1,133    756 2,197
 1,516
Net Cash Flows Used for Investing ActivitiesNet Cash Flows Used for Investing Activities  (981)   (772)(2,068) (1,643)
Net Cash Flows from (Used for) Financing Activities   22    (84)
Net Cash Flows Used for Financing Activities(57) (35)
Net Increase (Decrease) in Cash and Cash EquivalentsNet Increase (Decrease) in Cash and Cash Equivalents   174    (100)72
 (162)
Cash and Cash Equivalents at End of PeriodCash and Cash Equivalents at End of Period $ 292  $ 179 $190
 $117

Cash from operations and short-term borrowings provides working capital and allows us to meet other short-term cash needs.

30


 
Operating Activities
      
  Three Months Ended
  March 31,Six Months Ended 
 June 30,
  2014  2013 2014 2013
  (in millions)(in millions)
Net IncomeNet Income $ 561  $ 364 $952
 $703
Depreciation and AmortizationDepreciation and Amortization  491    420 934
 863
OtherOther   81    (28)311
 (50)
Net Cash Flows from Operating ActivitiesNet Cash Flows from Operating Activities $ 1,133  $ 756 $2,197
 $1,516

Net Cash Flows from Operating Activities were $1.1$2.2 billion in 2014 consisting primarily of Net Income of $561$952 million and $491$934 million of noncash Depreciation and Amortization partially offset by $137$105 million of fuel cost deferrals and $56$99 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. The reduction in Fuel, Material and Supplies balances reflects a decrease in fuel inventory due to the cold winter weather and increased generation.

Net Cash Flows from Operating Activities were $756 million$1.5 billion in 2013 consisting primarily of Net Income of $364$703 million, and $420$863 million of noncash Depreciation and Amortization.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 outflowsflows for Accrued Taxes were a result of recording the estimated federal tax loss forassociated with tax/book temporary differences.differences and the recognition of the tax benefit related to the U.K. Windfall Tax.

22
Investing Activities
      
  Three Months Ended
  March 31,Six Months Ended 
 June 30,
  2014  2013 2014 2013
  (in millions)(in millions)
Construction ExpendituresConstruction Expenditures $ (907) $ (843)$(1,883) $(1,637)
Acquisitions of Nuclear FuelAcquisitions of Nuclear Fuel  (49)   (47)(58) (59)
Acquisitions of Assets/BusinessesAcquisitions of Assets/Businesses  (43)   (2)(45) (4)
Insurance Proceeds Related to Cook Plant FireInsurance Proceeds Related to Cook Plant Fire  -    72 —
 72
Proceeds from Sales of Assets2
 11
OtherOther   18    48 (84) (26)
Net Cash Flows Used for Investing ActivitiesNet Cash Flows Used for Investing Activities $ (981) $ (772)$(2,068) $(1,643)

Net Cash Flows Used for Investing Activities were $981 million$2.1 billion in 2014 primarily due to Construction Expenditures for environmental, distribution and transmission investments. We also purchased transmission assets for $38 million.

Net Cash Flows Used for Investing Activities were $772 million$1.6 billion in 2013 primarily due to Construction Expenditures for environmental, distribution and transmission investments.
 

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Financing Activities
      
  Three Months Ended
  March 31,Six Months Ended 
 June 30,
  2014  2013 2014 2013
  (in millions)(in millions)
Issuance of Common Stock, NetIssuance of Common Stock, Net $ 15  $ 15 $29
 $41
Issuance of Debt, NetIssuance of Debt, Net  281    139 459
 425
Dividends Paid on Common StockDividends Paid on Common Stock  (245)   (230)(490) (469)
OtherOther   (29)   (8)(55) (32)
Net Cash Flows from (Used for) Financing Activities $ 22  $ (84)
Net Cash Flows Used for Financing Activities$(57) $(35)

Net Cash Flows fromUsed for Financing Activities in 2014 were $22$57 million. Our net debt issuances were $281$459 million. The net issuances included issuances of $76$530 million of senior unsecured notes, $304 million of pollution control bonds and $114 million of other debt notes and an increase in short-term borrowing of $575$725 million offset by retirements of $258$794 million of senior unsecured and other debt notes, $273 million of pollution control bonds and $112$138 million of securitization bonds. We paid common stock dividends of $245$490 million. See Note 11 –12 - Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows Used for Financing Activities in 2013 were $84$35 million. Our net debt issuances were $139$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 $326$557 million offset by retirements of $753$796 million of senior unsecured and other debt notes, and $105$131 million of securitization bonds and $146 million of pollution control bonds. We paid common stock dividends of $230$469 million.

In AprilJuly 2014, I&M retired $13$9 million of Notes Payable related to DCC Fuel.

In July 2014, OPCo retired $35 million of Securitization Bonds.

In July 2014, SWEPCo issued a $100 million three-year term credit facility and drew the full amount.

In July 2014, TCC retired $112 million of Securitization Bonds.

BUDGETED CONSTRUCTION EXPENDITURES

In April 2014, we increased our forecast for construction expenditures by $250$350 million to approximately $4.1$4.2 billion for 2014. The increase is primarily for transmission investment in the AEP Transmission Holdco, Vertically Integrated Utilities and Transmission and Distribution Utilities segments.

23
OFF-BALANCE SHEET ARRANGEMENTS

Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that we enter in the normal course of business.  The following identifies significant off-balance sheet arrangements:

  March 31, December 31,
  2014  2013 June 30,
2014		 December 31,
2013
  (in millions)(in millions)
Rockport Plant, Unit 2 Future Minimum Lease PaymentsRockport Plant, Unit 2 Future Minimum Lease Payments $ 1,330  $ 1,330 $1,256
 $1,330
Railcars Maximum Potential Loss from Lease AgreementRailcars Maximum Potential Loss from Lease Agreement  19    19 19
 19


32


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 2013 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2013 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 2013 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

Pronouncements Effective in the Future

The FASB issued ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held for saleheld-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. We plan to adopt ASU 2014-08 effective January 1, 2015.

The FASB issued ASU 2014-09 "Revenue from Contracts with Customers" clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. We plan to adopt ASU 2014-09 effective January 1, 2017.

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.


33
24


QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

Our Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through its transactions in power, coal, natural gas 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 Transmission and Distribution Utilities segment is exposed to FTR price risk as it relates to congestion during the June 2012 –- May 2015 Ohio ESP period. Additional risk includes interest rate risk.

Our Generation & 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. In addition, our Generation & Marketing segment is also exposed to certain market risks as a major power producer and through its transactions in wholesale electricity, natural gas and coal trading and marketing contracts.

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, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with our energy business.  As a result, we are subject to price risk.  The amount of risk taken is determined by the Commercial Operations, Energy Supply, and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.  Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.  The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, and Chief Risk Officer in addition to AEP Energy Supply’s President and Vice President.  When commercial activities exceed predetermined limits, we modify the positions to reduce the risk to be within the limits unless specifically approved by the respective committee.


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The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2013:

 MTM Risk Management Contract Net Assets (Liabilities)
 Three Months Ended March 31, 2014
             
     Transmission      
  Vertically and Generation  
  Integrated Distributionand 
  Utilities UtilitiesMarketingTotal
  (in millions)
Total MTM Risk Management Contract Net Assets           
 as of December 31, 2013$ 32  $  3  $ 157  $ 192 
Gain from Contracts Realized/Settled During           
 the Period and Entered in a Prior Period  (6)   (3)   (16)   (25)
Fair Value of New Contracts at Inception When Entered           
 During the Period (a)  -    -    5    5 
Net Option Premiums Paid for Unexercised or Unexpired           
 Option Contracts Entered During the Period  -    -    1    1 
Changes in Fair Value Due to Market Fluctuations           
 During the Period (b)  -    -    11    11 
Changes in Fair Value Allocated to Regulated           
 Jurisdictions (c)  10    4    -    14 
Total MTM Risk Management Contract Net Assets           
 as of March 31, 2014$ 36  $  4  $ 158    198 
             
Commodity Cash Flow Hedge Contracts
           8 
Interest Rate and Foreign Currency Cash Flow Hedge 
           
 Contracts           (2)
Fair Value Hedge Contracts           (8)
Collateral Deposits           (2)
Total MTM Derivative Contract Net Assets as of           
 March 31, 2014         $ 194 
MTM Risk Management Contract Net Assets (Liabilities)
Six Months Ended June 30, 2014
        
 
Vertically
Integrated
Utilities
 
Transmission
and
Distribution
Utilities
 
Generation
&
Marketing
 Total
 (in millions)
Total MTM Derivative Contract Net Assets as of December 31, 2013$32
 $3
 $157
 $192
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period(1) (3) (25) (29)
Fair Value of New Contracts at Inception When Entered During the Period (a)—
 —
 6
 6
Changes in Fair Value Due to Market Fluctuations During the Period (b)—
 —
 19
 19
Changes in Fair Value Allocated to Regulated Jurisdictions (c)19
 9
 —
 28
Total MTM Derivative Contract Net Assets as of June 30, 2014$50
 $9
 $157
 $216
Commodity Cash Flow Hedge Contracts
   
  
 11
Interest Rate and Foreign Currency Cash Flow Hedge Contracts
   
  
 (2)
Fair Value Hedge Contracts   
  
 (5)
Collateral Deposits   
  
 (25)
Total MTM Derivative Contract Net Assets as of June 30, 2014   
  
 $195

(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 89 – Derivatives and Hedging and Note 910 – 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.

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.


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26


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 March 31,June 30, 2014, our credit exposure net of collateral to sub investment grade counterparties was approximately 9.2%9.6%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss). As of March 31,June 30, 2014, 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  Counterpartiesof
 CreditCreditNet>10% ofCounterparties
Counterparty Credit QualityCounterparty Credit QualityCollateralCollateralExposureNet Exposure>10% 
Exposure
Before
Credit
Collateral
 
Credit
Collateral
 
Net
Exposure
 Number of
Counterparties
>10% of
Net Exposure		 
Net Exposure
of
Counterparties
>10%
  (in millions, except number of counterparties) (in millions, except number of counterparties)
Investment GradeInvestment Grade $ 528  $ 10  $ 518   2  $ 256  $457
 $4
 $453
 2
 $228
Split RatingSplit Rating  -   -   -   -   -  —
 —
 —
 —
 —
Noninvestment GradeNoninvestment Grade  1   1   -   -   -  —
 —
 —
 —
 —
No External Ratings:No External Ratings:            
  
 

  
  
Internal Investment Grade  70   -   70   4   41 
Internal Noninvestment Grade   70    11    59    3    43 
Total as of March 31, 2014 $ 669  $ 22  $ 647    9  $ 340 
Internal Investment Grade 65
 —
 65
 4
 37
Internal Noninvestment Grade 66
 11
 55
 2
 36
Total as of June 30, 2014 $588
 $15
 $573
 8
 $301
                     
Total as of December 31, 2013Total as of December 31, 2013 $ 787  $ 18  $ 769    9  $ 381  $787
 $18
 $769
 9
 $381

In addition, we are exposed to credit risk related to our participation in RTOs. For each of the RTOs in which we participate, this risk is generally determined based on our proportionate share of member gross activity over a specified period of time.

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 March 31,June 30, 2014, 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

Three Months Ended Twelve Months Ended
March 31, 2014 December 31, 2013
Six Months EndedSix Months Ended Twelve Months Ended
June 30, 2014June 30, 2014 December 31, 2013
EndEnd High Average Low End High Average LowEnd High Average Low End High Average Low
(in millions)(in millions) (in millions)(in millions) (in millions)
$1  $3  $1  $-  $-  $1  $-  $- —
 $3
 $1
 $—
 $—
 $1
 $—
 $—

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

As our VaR calculation captures recent price movements, we also perform regular stress testing of the portfolio to understand our exposure to extreme price movements. We employ a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last several 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, Regulated Risk Committee, or Competitive Risk Committee as appropriate.

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27

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 March 31,June 30, 2014 and December 31, 2013, the estimated EaR on our debt portfolio for the following twelve months was $33$29 million and $32 million, respectively.

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28

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2014 and 2013
 (in millions, except per-share and share amounts)
(Unaudited)
        
   Three Months Ended March 31,
   2014  2013 
REVENUES      
Vertically Integrated Utilities $ 2,549  $ 2,356 
Transmission and Distribution Utilities   1,161    1,090 
Generation & Marketing   821    258 
Other Revenues   117    122 
TOTAL REVENUES   4,648    3,826 
EXPENSES      
Fuel and Other Consumables Used for Electric Generation   1,168    1,031 
Purchased Electricity for Resale   638    371 
Other Operation   780    738 
Maintenance   292    293 
Depreciation and Amortization   491    420 
Taxes Other Than Income Taxes   238    218 
TOTAL EXPENSES   3,607    3,071 
        
OPERATING INCOME   1,041    755 
        
Other Income (Expense):      
Interest and Investment Income   1    3 
Carrying Costs Income   6    4 
Allowance for Equity Funds Used During Construction   22    15 
Interest Expense   (220)   (232)
        
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS   850    545 
        
Income Tax Expense   307    195 
Equity Earnings of Unconsolidated Subsidiaries   18    14 
        
NET INCOME   561    364 
        
Net Income Attributable to Noncontrolling Interests   1    1 
        
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 560  $ 363 
        
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING  487,867,089   485,823,668 
        
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON      
 SHAREHOLDERS $ 1.15  $ 0.75 
        
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING  488,271,167   486,344,036 
        
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON      
 SHAREHOLDERS $ 1.15  $ 0.75 
        
CASH DIVIDENDS DECLARED PER SHARE $ 0.50  $ 0.47 
        
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 35.

29


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2014 and 2013
(in millions)
(Unaudited)
        
   Three Months Ended March 31,
   2014  2013 
Net Income $ 561  $ 364 
        
OTHER COMPREHENSIVE INCOME, NET OF TAXES      
Cash Flow Hedges, Net of Tax of $3 and $13 in 2014 and 2013, Respectively   5    24 
Securities Available for Sale, Net of Tax of $- and $1 in 2014 and 2013, Respectively   -    1 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $- and $3 in 2014      
 and 2013, Respectively   1    6 
        
TOTAL OTHER COMPREHENSIVE INCOME   6    31 
        
TOTAL COMPREHENSIVE INCOME   567    395 
        
Total Comprehensive Income Attributable to Noncontrolling Interests   1    1 
       
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP      
 COMMON SHAREHOLDERS $ 566  $ 394 
        
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 35.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2014 and 2013
(in millions, except per-share and share amounts)
(Unaudited)
  Three Months Ended Six Months Ended
  June 30, June 30,
  2014 2013 2014 2013
REVENUES        
Vertically Integrated Utilities $2,236
 $2,176
 $4,785
 $4,532
Transmission and Distribution Utilities 1,064
 1,019
 2,225
 2,109
Generation & Marketing 573
 298
 1,394
 556
Other Revenues 171
 89
 288
 211
TOTAL REVENUES 4,044
 3,582
 8,692
 7,408
         
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 1,043
 908
 2,211
 1,939
Purchased Electricity for Resale 473
 359
 1,111
 730
Other Operation 760
 664
 1,540
 1,402
Maintenance 340
 285
 632
 578
Asset Impairments and Other Related Charges —
 154
 —
 154
Depreciation and Amortization 443
 443
 934
 863
Taxes Other Than Income Taxes 218
 222
 456
 440
TOTAL EXPENSES 3,277
 3,035
 6,884
 6,106
         
OPERATING INCOME 767
 547
 1,808
 1,302
         
Other Income (Expense):  
  
  
  
Interest and Investment Income 3
 49
 4
 52
Carrying Costs Income 9
 8
 15
 12
Allowance for Equity Funds Used During Construction 25
 17
 47
 32
Interest Expense (221) (228) (441) (460)
         
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS 583
 393
 1,433
 938
         
Income Tax Expense 215
 68
 522
 263
Equity Earnings of Unconsolidated Subsidiaries 23
 14
 41
 28
         
NET INCOME 391
 339
 952
 703
         
Net Income Attributable to Noncontrolling Interests 1
 1
 2
 2
         
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $390
 $338
 $950
 $701
         
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING 488,291,576
 486,293,026
 488,080,505
 486,059,643
         
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $0.80
 $0.69
 $1.95
 $1.44
         
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING 488,538,227
 486,763,615
 488,405,869
 486,555,121
         
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $0.80
 $0.69
 $1.95
 $1.44
         
CASH DIVIDENDS DECLARED PER SHARE $0.50
 $0.49
 $1.00
 $0.96
         
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 44.


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30



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Three Months Ended March 31, 2014 and 2013
(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, 2012  506  $  3,289  $  6,049  $  6,236  $  (337) $  -  $  15,237 
                     
Issuance of Common Stock     2    13             15 
Common Stock Dividends           (229)      (1)   (230)
Other Changes in Equity        4             4 
Net Income           363       1    364 
Other Comprehensive Income              31       31 
TOTAL EQUITY – MARCH 31, 2013  506  $  3,291  $  6,066  $  6,370  $  (306) $  -  $  15,421 
                     
TOTAL EQUITY – DECEMBER 31, 2013  508  $  3,303  $  6,131  $  6,766  $  (115) $  1  $ 16,086 
                     
Issuance of Common Stock     2    13             15 
Common Stock Dividends           (244)      (1)   (245)
Other Changes in Equity           (6)      2    (4)
Net Income           560       1    561 
Other Comprehensive Income              6       6 
TOTAL EQUITY – MARCH 31, 2014  508  $  3,305  $  6,144  $  7,076  $  (109) $  3  $  16,419 
                     
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 35.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2014 and 2013
(in millions)
(Unaudited)
  Three Months Ended Six Months Ended
  June 30, June 30,
  2014 2013 2014 2013
Net Income $391
 $339
 $952
 $703
         
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
  
  
  
Cash Flow Hedges, Net of Tax of $1 and $5 for the Three Months Ended
June 30, 2014 and 2013, Respectively, and $4 and $8 for the Six
Months Ended June 30, 2014 and 2013, Respectively
 3
 (10) 8
 14
Securities Available for Sale, Net of Tax of $0 and $0 for the Three Months
Ended June 30, 2014 and 2013, Respectively, and $0 and $0 for the
Six Months Ended June 30, 2014 and 2013, Respectively
 1
 —
 1
 1
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1
and $2 for the Three Months Ended June 30, 2014 and 2013,
Respectively, and $1 and $5 for the Six Months Ended June 30,
2014 and 2013, Respectively
 1
 3
 2
 9
         
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) 5
 (7) 11
 24
         
TOTAL COMPREHENSIVE INCOME 396
 332
 963
 727
         
Total Comprehensive Income Attributable to Noncontrolling Interests 1
 1
 2
 2
         
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
COMMON SHAREHOLDERS
 $395
 $331
 $961
 $725
         
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 44.


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31


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 30, 2014 and 2013
(in millions)
(Unaudited)
 AEP Common Shareholders    
 Common Stock     
Accumulated
Other
Comprehensive
Income (Loss)
    
 Shares Amount 
Paid-in
Capital
 
Retained
Earnings
  
Noncontrolling
Interests
 Total
TOTAL EQUITY - DECEMBER 31, 2012506
 $3,289
 $6,049
 $6,236
 $(337) $—
 $15,237
              
Issuance of Common Stock1
 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, 2013507
 $3,296
 $6,084
 $6,470
 $(313) $—
 $15,537
              
TOTAL EQUITY - DECEMBER 31, 2013508
 $3,303
 $6,131
 $6,766
 $(115) $1
 $16,086
              
Issuance of Common Stock1
 5
 24
  
  
  
 29
Common Stock Dividends 
  
  
 (488)  
 (2) (490)
Other Changes in Equity 
  
 

 (6)  
 3
 (3)
Net Income      950
  
 2
 952
Other Comprehensive Income 
  
  
  
 11
  
 11
TOTAL EQUITY - JUNE 30, 2014509
 $3,308
 $6,155
 $7,222
 $(104) $4
 $16,585
              
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 44.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2014 and December 31, 2013
(in millions)
(Unaudited)
 
        March 31, December 31,
  2014  2013 
CURRENT ASSETS      
Cash and Cash Equivalents $ 292  $ 118 
Other Temporary Investments      
 (March 31, 2014 and December 31, 2013 Amounts Include $293 and $335, Respectively, Related to Transition Funding, Phase-in-Recovery Funding, Consumer Rate Relief Funding and EIS)   310    353 
Accounts Receivable:      
 Customers   785    746 
 Accrued Unbilled Revenues   143    157 
 Pledged Accounts Receivable - AEP Credit   1,015    945 
 Miscellaneous   66    72 
 Allowance for Uncollectible Accounts   (66)   (60)
  Total Accounts Receivable   1,943    1,860 
Fuel   490    701 
Materials and Supplies   724    722 
Risk Management Assets   125    160 
Regulatory Asset for Under-Recovered Fuel Costs   175    80 
Margin Deposits   117    70 
Prepayments and Other Current Assets   159    246 
TOTAL CURRENT ASSETS   4,335    4,310 
       
PROPERTY, PLANT AND EQUIPMENT      
Electric:      
 Generation   25,174    25,074 
 Transmission   11,014    10,893 
 Distribution   16,518    16,377 
Other Property, Plant and Equipment (Including Plant to be Retired, Coal Mining      
 and Nuclear Fuel)   5,552    5,470 
Construction Work in Progress   2,836    2,471 
Total Property, Plant and Equipment   61,094    60,285 
Accumulated Depreciation and Amortization   19,564    19,288 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET   41,530    40,997 
       
OTHER NONCURRENT ASSETS      
Regulatory Assets   4,384    4,376 
Securitized Assets   2,308    2,373 
Spent Nuclear Fuel and Decommissioning Trusts   1,962    1,932 
Goodwill   91    91 
Long-term Risk Management Assets   266    297 
Deferred Charges and Other Noncurrent Assets   2,162    2,038 
TOTAL OTHER NONCURRENT ASSETS   11,173    11,107 
       
TOTAL ASSETS $ 57,038  $ 56,414 
       
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 35.
32
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 2014 and December 31, 2013
(dollars in millions)
(Unaudited)
 
        March 31, December 31,
  2014  2013 
CURRENT LIABILITIES      
Accounts Payable $ 1,213  $ 1,266 
Short-term Debt:      
 Securitized Debt for Receivables - AEP Credit    700    700 
 Other Short-term Debt    632    57 
  Total Short-term Debt    1,332    757 
Long-term Debt Due Within One Year      
 (March 31, 2014 and December 31, 2013 Amounts Include $449 and $416, Respectively, Related to Transition Funding, DCC Fuel, Phase-in-Recovery Funding, Consumer Rate Relief Funding and Sabine)   1,612    1,549 
Risk Management Liabilities   60    90 
Customer Deposits   302    299 
Accrued Taxes   803    822 
Accrued Interest   220    245 
Regulatory Liability for Over-Recovered Fuel Costs   60    119 
Other Current Liabilities   917    965 
TOTAL CURRENT LIABILITIES   6,519    6,112 
       
NONCURRENT LIABILITIES      
Long-term Debt      
 (March 31, 2014 and December 31, 2013 Amounts Include $2,388 and $2,532, Respectively, Related to Transition Funding, DCC Fuel, Phase-in-Recovery Funding, Consumer Rate Relief Funding, Transource Energy and Sabine)   16,475    16,828 
Long-term Risk Management Liabilities   137    177 
Deferred Income Taxes   10,446    10,300 
Regulatory Liabilities and Deferred Investment Tax Credits   3,765    3,694 
Asset Retirement Obligations   1,853    1,835 
Employee Benefits and Pension Obligations   456    415 
Deferred Credits and Other Noncurrent Liabilities   968    967 
TOTAL NONCURRENT LIABILITIES   34,100    34,216 
       
TOTAL LIABILITIES   40,619    40,328 
       
Rate Matters (Note 4)      
Commitments and Contingencies (Note 5)      
       
EQUITY      
Common Stock – Par Value – $6.50 Per Share:      
   2014  2013        
 Shares Authorized600,000,000  600,000,000        
 Shares Issued508,397,086  508,113,964        
(20,336,592 Shares were Held in Treasury as of March 31, 2014 and December 31, 2013)   3,305    3,303 
Paid-in Capital   6,144    6,131 
Retained Earnings   7,076    6,766 
Accumulated Other Comprehensive Income (Loss)   (109)   (115)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY   16,416    16,085 
       
Noncontrolling Interests   3    1 
       
TOTAL EQUITY   16,419    16,086 
       
TOTAL LIABILITIES AND EQUITY $ 57,038  $ 56,414 
       
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 35.


40
33



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2014 and 2013
(in millions)
(Unaudited)
 
    Three Months Ended March 31,
  2014  2013 
OPERATING ACTIVITIES      
Net Income $ 561  $ 364 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:      
 Depreciation and Amortization   491    420 
 Deferred Income Taxes   299    246 
 Carrying Costs Income   (6)   (4)
 Allowance for Equity Funds Used During Construction   (22)   (15)
 Mark-to-Market of Risk Management Contracts   6    34 
 Amortization of Nuclear Fuel   38    34 
 Property Taxes   (54)   (51)
 Fuel Over/Under-Recovery, Net   (137)   (4)
 Deferral of Ohio Capacity Costs, Net   (56)   (49)
 Change in Other Noncurrent Assets   (25)   36 
 Change in Other Noncurrent Liabilities   77    17 
 Changes in Certain Components of Working Capital:      
  Accounts Receivable, Net   (83)   (4)
  Fuel, Materials and Supplies   209    (1)
  Accounts Payable   33    (3)
  Accrued Taxes, Net   (16)   (69)
  Other Current Assets   (51)   (16)
  Other Current Liabilities   (131)   (179)
Net Cash Flows from Operating Activities   1,133    756 
       
INVESTING ACTIVITIES      
Construction Expenditures   (907)   (843)
Change in Other Temporary Investments, Net   44    75 
Purchases of Investment Securities   (165)   (196)
Sales of Investment Securities   148    168 
Acquisitions of Nuclear Fuel   (49)   (47)
Acquisitions of Assets/Businesses   (43)   (2)
Insurance Proceeds Related to Cook Plant Fire   -    72 
Other Investing Activities   (9)   1 
Net Cash Flows Used for Investing Activities   (981)   (772)
       
FINANCING ACTIVITIES      
Issuance of Common Stock, Net   15    15 
Issuance of Long-term Debt   76    671 
Commercial Paper and Credit Facility Borrowings   -    17 
Change in Short-term Debt, Net   575    329 
Retirement of Long-term Debt   (370)   (858)
Commercial Paper and Credit Facility Repayments   -    (20)
Principal Payments for Capital Lease Obligations   (33)   (16)
Dividends Paid on Common Stock   (245)   (230)
Other Financing Activities   4    8 
Net Cash Flows from (Used for) Financing Activities   22    (84)
       
Net Increase (Decrease) in Cash and Cash Equivalents   174    (100)
Cash and Cash Equivalents at Beginning of Period   118    279 
Cash and Cash Equivalents at End of Period $ 292  $ 179 
       
SUPPLEMENTARY INFORMATION      
Cash Paid for Interest, Net of Capitalized Amounts $ 234  $ 253 
Net Cash Paid (Received) for Income Taxes   (6)   (19)
Noncash Acquisitions Under Capital Leases   20    24 
Construction Expenditures Included in Current Liabilities as of March 31,   387    300 
       
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 35.
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2014 and December 31, 2013
(in millions)
(Unaudited)
  June 30, December 31,
  2014 2013
CURRENT ASSETS  
  
Cash and Cash Equivalents $190
 $118
Other Temporary Investments
(June 30, 2014 and December 31, 2013 Amounts Include $360 and $335, Respectively, Related to Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and EIS)
 377
 353
Accounts Receivable:  
  
Customers 774
 746
Accrued Unbilled Revenues 59
 157
Pledged Accounts Receivable – AEP Credit 1,060
 945
Miscellaneous 60
 72
Allowance for Uncollectible Accounts (27) (60)
Total Accounts Receivable 1,926
 1,860
Fuel 471
 701
Materials and Supplies 748
 722
Risk Management Assets 146
 160
Regulatory Asset for Under-Recovered Fuel Costs 158
 80
Margin Deposits 78
 70
Prepayments and Other Current Assets 229
 246
TOTAL CURRENT ASSETS 4,323
 4,310
     
PROPERTY, PLANT AND EQUIPMENT  
  
Electric:  
  
Generation 25,401
 25,074
Transmission 11,420
 10,893
Distribution 16,716
 16,377
Other Property, Plant and Equipment (Including Plant to be Retired, Coal Mining and Nuclear Fuel) 5,642
 5,470
Construction Work in Progress 2,886
 2,471
Total Property, Plant and Equipment 62,065
 60,285
Accumulated Depreciation and Amortization 19,792
 19,288
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 42,273
 40,997
     
OTHER NONCURRENT ASSETS  
  
Regulatory Assets 4,390
 4,376
Securitized Assets 2,244
 2,373
Spent Nuclear Fuel and Decommissioning Trusts 2,019
 1,932
Goodwill 91
 91
Long-term Risk Management Assets 224
 297
Deferred Charges and Other Noncurrent Assets 2,056
 2,038
TOTAL OTHER NONCURRENT ASSETS 11,024
 11,107
     
TOTAL ASSETS $57,620
 $56,414
     
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 44.


41


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2014 and December 31, 2013
(dollars in millions)
(Unaudited)
       June 30, December 31,
       2014 2013
CURRENT LIABILITIES    
Accounts Payable      $1,228
 $1,266
Short-term Debt:         
Securitized Debt for Receivables - AEP Credit    750
 700
Other Short-term Debt      732
 57
Total Short-term Debt      1,482
 757
Long-term Debt Due Within One Year
(June 30, 2014 and December 31, 2013 Amounts Include $434 and $416, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine)
  2,524
 1,549
Risk Management Liabilities      60
 90
Customer Deposits      306
 299
Accrued Taxes      692
 822
Accrued Interest      240
 245
Regulatory Liability for Over-Recovered Fuel Costs    58
 119
Other Current Liabilities      1,010
 965
TOTAL CURRENT LIABILITIES      7,600
 6,112
          
NONCURRENT LIABILITIES    
Long-term Debt         
(June 30, 2014 and December 31, 2013 Amounts Include $2,359 and $2,532, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy and Sabine)  15,601
 16,828
Long-term Risk Management Liabilities      115
 177
Deferred Income Taxes      10,463
 10,300
Regulatory Liabilities and Deferred Investment Tax Credits  3,840
 3,694
Asset Retirement Obligations      1,908
 1,835
Employee Benefits and Pension Obligations      411
 415
Deferred Credits and Other Noncurrent Liabilities  1,097
 967
TOTAL NONCURRENT LIABILITIES      33,435
 34,216
          
TOTAL LIABILITIES      41,035
 40,328
          
Rate Matters (Note 4)      
 
Commitments and Contingencies (Note 5)      
 
          
EQUITY    
Common Stock – Par Value – $6.50 Per Share:         
  2014 2013     
Shares Authorized 600,000,000 600,000,000     
Shares Issued 508,902,340 508,113,964     
(20,336,592 Shares were Held in Treasury as of June 30, 2014 and December 31, 2013)  3,308
 3,303
Paid-in Capital      6,155
 6,131
Retained Earnings      7,222
 6,766
Accumulated Other Comprehensive Income (Loss)  (104) (115)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY  16,581
 16,085
          
Noncontrolling Interests      4
 1
          
TOTAL EQUITY      16,585
 16,086
          
TOTAL LIABILITIES AND EQUITY      $57,620
 $56,414
          
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 44.

34
42


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2014 and 2013
(in millions)
(Unaudited)
  Six Months Ended June 30,
  2014 2013
OPERATING ACTIVITIES  
  
Net Income $952
 $703
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
Depreciation and Amortization 934
 863
Deferred Income Taxes 410
 367
Asset Impairments and Other Related Charges —
 154
Carrying Costs Income (15) (12)
Allowance for Equity Funds Used During Construction (47) (32)
Mark-to-Market of Risk Management Contracts 9
 16
Amortization of Nuclear Fuel 79
 63
Pension Contributions to Qualified Plan Trust (71) —
Property Taxes 92
 68
Fuel Over/Under-Recovery, Net (105) (4)
Deferral of Ohio Capacity Costs, Net (99) (102)
Change in Other Noncurrent Assets 11
 (20)
Change in Other Noncurrent Liabilities 132
 12
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net (73) (53)
Fuel, Materials and Supplies 207
 (61)
Accounts Payable (39) (57)
Accrued Taxes, Net (86) (214)
Other Current Assets (3) (10)
Other Current Liabilities (91) (165)
Net Cash Flows from Operating Activities 2,197
 1,516
     
INVESTING ACTIVITIES    
Construction Expenditures (1,883) (1,637)
Change in Other Temporary Investments, Net (24) 38
Purchases of Investment Securities (510) (423)
Sales of Investment Securities 483
 385
Acquisitions of Nuclear Fuel (58) (59)
Acquisitions of Assets/Businesses (45) (4)
Insurance Proceeds Related to Cook Plant Fire —
 72
Proceeds from Sales of Assets 2
 11
Other Investing Activities (33) (26)
Net Cash Flows Used for Investing Activities (2,068) (1,643)
     
FINANCING ACTIVITIES    
Issuance of Common Stock, Net 29
 41
Issuance of Long-term Debt 939
 941
Commercial Paper and Credit Facility Borrowings —
 17
Change in Short-term Debt, Net 725
 560
Retirement of Long-term Debt (1,205) (1,073)
Commercial Paper and Credit Facility Repayments —
 (20)
Principal Payments for Capital Lease Obligations (60) (33)
Dividends Paid on Common Stock (490) (469)
Other Financing Activities 5
 1
Net Cash Flows Used for Financing Activities (57) (35)
     
Net Increase (Decrease) in Cash and Cash Equivalents 72
 (162)
Cash and Cash Equivalents at Beginning of Period 118
 279
Cash and Cash Equivalents at End of Period $190
 $117
     
SUPPLEMENTARY INFORMATION    
Cash Paid for Interest, Net of Capitalized Amounts $422
 $455
Net Cash Paid (Received) for Income Taxes 63
 (10)
Noncash Acquisitions Under Capital Leases 33
 31
Construction Expenditures Included in Current Liabilities as of June 30, 432
 297
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, 42
 41
     
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 44.


43


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

Page
 
Page
Number
  
Significant Accounting Matters36
45
New Accounting PronouncementPronouncements37
47
Comprehensive Income37
48
Rate Matters39
51
Commitments, Guarantees and Contingencies46
61
Impairment
65
Benefit Plans49
66
Business Segments50
67
Derivatives and Hedging52
71
Fair Value Measurements58
78
Income Taxes65
87
Financing Activities66
88
Variable Interest Entities68
92


44
35


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 March 31,June 30, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014.  The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2013 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 25, 2014.

Revenue Recognition

Electricity Supply and Delivery Activities –- Transactions with PJM

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. For regulated and nonregulated operations, we recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.

APCo, I&M and KPCo sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary’s retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenue on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement in 2014, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices.

AEP’s nonregulated subsidiaries also purchase power from PJM and sell power to PJM. With the exception of certain dedicated load bilateral power supply contracts, these transactions are reported as gross purchases and sales.

SPP Integrated Power Market

In March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In the past, PSO and SWEPCo would satisfy their load requirements with their own generation resources or through the Operating Agreement. In the new integrated power market, PSO and SWEPCo operate as standalone entities by offering their respective generation into the SPP power market, which then economically dispatches the resources. This change further enables retail customers to obtain low cost power through either internal generation or power purchases from the SPP market. The new integrated power market now operates in a similar manner as the PJM power market for the AEP East Companies. No significant impact on results of operations is expected due to this change.


45


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 table presentstables present our basic and diluted EPS calculations included on our condensed statements of income:
 Three Months Ended June 30,
 2014 2013
 (in millions, except per share data)
  
 $/share   $/share
Earnings Attributable to AEP Common Shareholders$390
  
 $338
  
        
Weighted Average Number of Basic Shares Outstanding488.3
 $0.80
 486.3
 $0.69
Weighted Average Dilutive Effect of: 
  
  
  
Restricted Stock Units0.2
 —
 0.5
 —
Weighted Average Number of Diluted Shares Outstanding488.5
 $0.80
 486.8
 $0.69

   Three Months Ended March 31,
   2014  2013 
   (in millions, except per share data)
      $/share    $/share
Earnings Attributable to AEP Common Shareholders $ 560     $ 363    
              
Weighted Average Number of Basic Shares Outstanding   487.9  $ 1.15    485.8  $ 0.75 
Weighted Average Dilutive Effect of:            
 Restricted Stock Units   0.4    -    0.5    - 
Weighted Average Number of Diluted Shares Outstanding   488.3  $ 1.15    486.3  $ 0.75 
 Six Months Ended June 30,
 2014 2013
 (in millions, except per share data)
  
 $/share   $/share
Earnings Attributable to AEP Common Shareholders$950
  
 $701
  
        
Weighted Average Number of Basic Shares Outstanding488.1
 $1.95
 486.1
 $1.44
Weighted Average Dilutive Effect of: 
  
  
  
Restricted Stock Units0.3
 —
 0.5
 —
Weighted Average Number of Diluted Shares Outstanding488.4
 $1.95
 486.6
 $1.44

There were no antidilutive shares outstanding as of March 31,June 30, 2014 and 2013.


46
36


2.  2. NEW ACCOUNTING PRONOUNCEMENTPRONOUNCEMENTS

Upon issuance of final pronouncements, we review the new accounting literature to determine its relevance, if any, to our business. The following summary of a final pronouncementpronouncements will impact our financial statements.

ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08)

In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held for saleheld-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of our financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. We plan to adopt ASU 2014-08 effective January 1, 2015.

ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09)

In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. This standard must be retrospectively applied to all reporting periods presented in financial reports issued after the effective date.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016. Early adoption is not permitted. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. We plan to adopt ASU 2014-09 effective January 1, 2017.


47


3.  COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI for the three and six months ended March 31,June 30, 2014 and 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 March 31, 2014
 
   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, 2013$ -  $ (23) $ 7  $ (99) $ (115)
Change in Fair Value Recognized in AOCI  (14)   -    -    -    (14)
Amounts Reclassified from AOCI  18    1    -    1    20 
Net Current Period Other              
  Comprehensive Income  4    1    -    1    6 
Balance in AOCI as of March 31, 2014$ 4  $ (22) $ 7  $ (98) $ (109)
                 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 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  18    3    1    -    22 
Amounts Reclassified from AOCI  2    1    -    6    9 
Net Current Period Other              
  Comprehensive Income  20    4    1    6    31 
Balance in AOCI as of March 31, 2013$ 12  $ (26) $ 5  $ (297) $ (306)
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2014
 Cash Flow Hedges      
 Commodity 
Interest Rate and
Foreign Currency
 
Securities
Available for Sale
 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of March 31, 2014$4
 $(22) $7
 $(98) $(109)
Change in Fair Value Recognized in AOCI3
 —
 1
 —
 4
Amounts Reclassified from AOCI(1) 1
 —
 1
 1
Net Current Period Other
Comprehensive Income
2
 1
 1
 1
 5
Balance in AOCI as of June 30, 2014$6
 $(21) $8
 $(97) $(104)

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2013
37
 Cash Flow Hedges      
 Commodity 
Interest Rate and
Foreign Currency
 
Securities
Available for Sale
 
Pension
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 (Loss)
(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, 2014
 Cash Flow Hedges      
 Commodity 
Interest Rate and
Foreign Currency
 
Securities
Available for Sale
 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2013$—
 $(23) $7
 $(99) $(115)
Change in Fair Value Recognized in AOCI(11) —
 1
 —
 (10)
Amounts Reclassified from AOCI17
 2
 —
 2
 21
Net Current Period Other
Comprehensive Income
6
 2
 1
 2
 11
Balance in AOCI as of June 30, 2014$6
 $(21) $8
 $(97) $(104)


48


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2013
 Cash Flow Hedges      
 Commodity 
Interest Rate and
Foreign Currency
 
Securities
Available for Sale
 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2012$(8) $(30) $4
 $(303) $(337)
Change in Fair Value Recognized in AOCI10
 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)

Reclassifications from Accumulated Other Comprehensive Income

The following table providestables provide details of reclassifications from AOCI for the three and six months ended March 31,June 30, 2014 and 2013.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs.  See Note 67 for additional details.

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended March 31, 2014 and 2013
         
    Amount of (Gain) Loss
    Reclassified from AOCI
         
    Three Months Ended March 31,
    2014  2013 
Gains and Losses on Cash Flow Hedges (in millions)
Commodity:      
  Vertically Integrated Utilities Revenues $ -  $ - 
  Generation & Marketing Revenues   -    (3)
  Purchased Electricity for Resale   31    6 
  Property, Plant and Equipment   -    - 
  Regulatory Assets/(Liabilities), Net (a)   (3)   - 
Subtotal - Commodity   28    3 
         
Interest Rate and Foreign Currency:      
  Interest Expense   2    2 
Subtotal - Interest Rate and Foreign Currency   2    2 
         
Reclassifications from AOCI, before Income Tax (Expense) Credit   30    5 
Income Tax (Expense) Credit   11    2 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit   19    3 
       
Gains and Losses on Securities Available for Sale      
Interest Income   -    - 
Interest Expense   -    - 
Reclassifications from AOCI, before Income Tax (Expense) Credit   -    - 
Income Tax (Expense) Credit   -    - 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit   -    - 
        
Pension and OPEB      
Amortization of Prior Service Cost (Credit)   (5)   (5)
Amortization of Actuarial (Gains)/Losses   7    14 
Reclassifications from AOCI, before Income Tax (Expense) Credit   2    9 
Income Tax (Expense) Credit   1    3 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit   1    6 
         
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 20  $ 9 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended June 30, 2014 and 2013
  
Amount of (Gain) Loss
Reclassified from AOCI
  Three Months Ended June 30,
  2014 2013
Gains and Losses on Cash Flow Hedges (in millions)
Commodity:  
  
Vertically Integrated Utilities Revenues $—
 $—
Generation & Marketing Revenues —
 (2)
Purchased Electricity for Resale (2) (2)
Property, Plant and Equipment —
 —
Regulatory Assets/(Liabilities), Net (a) —
 —
Subtotal - Commodity (2) (4)
   
  
Interest Rate and Foreign Currency:  
  
Interest Expense 2
 2
Subtotal - Interest Rate and Foreign Currency 2
 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)
     
Pension and OPEB  
  
Amortization of Prior Service Cost (Credit) (5) (4)
Amortization of Actuarial (Gains)/Losses 7
 9
Reclassifications from AOCI, before Income Tax (Expense) Credit 2
 5
Income Tax (Expense) Credit 1
 2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1
 3
   
  
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $1
 $2


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Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Six Months Ended June 30, 2014 and 2013
  
Amount of (Gain) Loss
Reclassified from AOCI
  Six Months Ended June 30,
  2014 2013
Gains and Losses on Cash Flow Hedges (in millions)
Commodity:  
  
Vertically Integrated Utilities Revenues $—
 $—
Generation & Marketing Revenues —
 (5)
Purchased Electricity for Resale 29
 4
Property, Plant and Equipment —
 —
Regulatory Assets/(Liabilities), Net (a) (3) —
Subtotal - Commodity 26
 (1)
   
  
Interest Rate and Foreign Currency:  
  
Interest Expense 4
 4
Subtotal - Interest Rate and Foreign Currency 4
 4
     
Reclassifications from AOCI, before Income Tax (Expense) Credit 30
 3
Income Tax (Expense) Credit 11
 1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 19
 2
     
Pension and OPEB  
  
Amortization of Prior Service Cost (Credit) (10) (9)
Amortization of Actuarial (Gains)/Losses 14
 23
Reclassifications from AOCI, before Income Tax (Expense) Credit 4
 14
Income Tax (Expense) Credit 2
 5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2
 9
   
  
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $21
 $11

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


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4.  RATE MATTERS

As discussed in the 2013 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2013 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 2014 and updates the 2013 Annual Report.
 
Regulatory Assets Not Yet Being RecoveredPending Final Regulatory Approval
   March 31, December 31,
   2014  2013 
Noncurrent Regulatory Assets (in millions)
Regulatory assets not yet being recovered pending future proceedings:     
       
Regulatory Assets Currently Earning a Return     
Storm Related Costs $ 21  $ 22 
Ohio Economic Development Rider  -    14 
Other Regulatory Assets Not Yet Being Recovered  -    4 
Regulatory Assets Currently Not Earning a Return     
Storm Related Costs  104    161 
Indiana Under-Recovered Capacity Costs  28    22 
IGCC Pre-Construction Costs  21    -  June 30, December 31,
Expanded Net Energy Charge - Coal Inventory  19    21  2014 2013
Noncurrent Regulatory Assets (in millions)
Mountaineer Carbon Capture and Storage Product Validation Facility  13    13     
Ormet Special Rate Recovery Mechanism  10    36 
Other Regulatory Assets Not Yet Being Recovered   34    37 
Total Regulatory Assets Not Yet Being Recovered $ 250  $ 330 
Regulatory Assets Currently Earning a Return    
Storm Related Costs $21
 $22
Ohio Economic Development Rider —
 14
Other Regulatory Assets Pending Final Regulatory Approval 7
 4
Regulatory Assets Currently Not Earning a Return  
  
Storm Related Costs 99
 161
IGCC Pre-Construction Costs 21
 —
Expanded Net Energy Charge - Coal Inventory 14
 21
Mountaineer Carbon Capture and Storage Product Validation Facility 13
 13
Ormet Special Rate Recovery Mechanism 10
 36
Indiana Under-Recovered Capacity Costs —
 22
Other Regulatory Assets Pending Final Regulatory Approval 34
 37
Total Regulatory Assets Pending Final Regulatory ApprovalTotal Regulatory Assets Pending Final Regulatory Approval$219
 $330

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 Filings

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 (OCC) 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 March 31, 2014, OPCo’s net deferred fuel balance was $426 million, excluding unrecognized equity carrying costs. In February 2014, the Supreme Court of Ohio affirmed the PUCO’s decision and rejected all appeals filed by the OCC and the IEU. In February 2014, the IEU filed for reconsideration of the Supreme Court of Ohio decision.decision, which was subsequently denied in May 2014. As of June 30, 2014, OPCo’s net deferred fuel balance was $411 million, excluding unrecognized equity carrying costs.


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In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 –- 2011 ESP order, which granted a weighted average cost of capital rate. In November 2012, the IEU and the OCC filed appeals regarding
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the PUCO decision in the PIRR proceeding. These appeals principally argued that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo’s net deferred fuel balance up to the total balance.full amount. These intervenors’ appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of March 31,June 30, 2014, could reduce carrying costs by $30$29 million including $16$15 million of unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending.

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

June 2012 – May 2015 ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015. This ruling 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 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 OPCo RPM price collected from CRES providers, which includes reserve margins, iswas approximately $33/$34/MW day through May 2014 and $148/is $150/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR is beingwas collected from customers at $3.50/MWh through May 2014 and will beis currently collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. As of March 31,June 30, 2014, OPCo’sOPCo's incurred deferred capacity costs balance of $348$396 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

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

In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications.  The modifications includewhich included the delay of the energy auctions that were originally ordered in the ESP order. As ordered, in February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. Also as ordered, in May 2014, OPCo conducted an additional energy-only auction for 25% of the SSO load with delivery beginning November 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50%25% of the SSO load with delivery beginning November 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. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an

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independent auditor in the 2012 –- 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In May 2014, an independent auditor was selected by the PUCO and an audit of the recovery of the fixed fuel costs began in June 2014. A final audit report is expected in the third quarter of 2014.

Proposed June 2015 –- May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to market.competitively procured SSO supply. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation
40
through OPCo. The proposal also includes a purchased power agreement rider (PPA) that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based purchase power agreement. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. Additionally, the application identifies OPCo’s intention to submitin July 2014, OPCo submitted a separate application to continue the RSR established in the June 2012 –- May 2015 ESP in whichto collect the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh, until the balance of the capacity deferrals has been collected. Management intends to file this application inIn May 2014, intervenors and the second quarterPUCO staff filed testimony that provided various recommendations including the rejection and/or modification of 2014.  A hearingvarious riders, including the DIR and the proposed PPA. Hearings at the PUCO in the ESP case is scheduled forwere held in June 2014.

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

Significantly Excessive Earnings Test (SEET) Filings

In January 2011, the PUCO issued an order on the 2009 SEET filing. The 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. In September 2013, a proposed second phase of OPCo’s gridSMART® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending.

In November 2013, OPCo filed its 2011 and 2012 SEET filingfilings with the PUCO.  OPCo was required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. In March 2014, the PUCO approved a stipulation agreement between OPCo and the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2011 for CSPCo or OPCo.

In November 2013, OPCo filed its 2012 SEET filing withMay 2014, the PUCO.  In April 2014, OPCo entered intoPUCO approved a stipulation agreement withbetween OPCo and the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2012 for OPCo. A hearing at the PUCO related to the 2012In May 2014, OPCo filed its 2013 SEET filing is scheduled for April 2014.with the PUCO. Management does not believe that there were significantly excessive earnings in 2013 for OPCo.2013.

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 and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo’s generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition.


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Storm Damage Recovery Rider (SDRR)

In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates to recover 2012 incremental storm distribution expenses over twelve months starting withexpenses. In April 2014, the effective date asPUCO approved by the PUCO.  In December 2013, a stipulation agreement was reached between OPCo, the PUCO staff and all intervenors, except the OCC.  The stipulation agreement recommended approvalOCC, to recover $55 million related to 2012 storm costs over a 12-month period which included a $6 million reduction in the amount of 2012 storm expenses to be recovered.period. The agreement also provided that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period. In April 2014, the PUCO approved the settlement agreement.  Compliance tariffs were filed with the PUCO and new rates were implemented in April 2014. In May 2014, the PUCO upheld the settlement agreement on rehearing.

2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo’s 2009 FAC 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. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 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. 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.

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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 Ohioultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC). The PUCO subsequently ruled in the PIRR proceeding that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes. Hearings at the PUCO were held in November 2013.  If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition.  See the 2009 –- 2011 ESP section of the “Ohio Electric Security Plan Filing” related to the PUCO order in the PIRR proceeding. In May 2014, the PUCO issued an order that generally approved OPCo's 2010-2011 fuel costs. The order rejected the auditor recommendation to adjust the WACC carrying charges related to accumulated deferred income taxes. Additionally, the PUCO requested further review related to an affiliate barging agreement and the modification of certain fuel procurement processes and practices.Further, the order provided for the auditor to address any remaining concerns in their next audit report, as they deem necessary. OPCo opposed these additional conditions in its application for rehearing in June 2014. In June 2014, the IEU filed an application with the PUCO for rehearing of this May 2014 order. In July 2014, the PUCO issued an order that denied all requests for rehearing.

2012 –and 2013 Fuel Adjustment Clause Audits

In AprilMay 2014, the PUCO-selected outside consultant provided its preliminary draftfinal report related to theirits 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the pending audit of the recovery of fixed fuel costs. See the "June 2012 – May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition.


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Ormet

Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware.  In October 2013, Ormet announced that it was unable to emerge from bankruptcyDelaware and subsequently shut down operations effective immediately.in October 2013. Based upon previous PUCO rulings providing rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider (EDR), except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet’s October and November 2012 power bills. OPCo expects that any additional unpaid generation usage by Ormet will be recoverable as a regulatory asset through the EDR. In February 2014, a stipulation agreement between OPCo and Ormet was filed with the PUCO. The stipulation recommendsrecommended approval of OPCo’s right to fully recover approximately $49 million of foregone revenues through the EDR which, as of March 31, 2014, is recorded in regulatory assets on the balance sheet.EDR. Also in February 2014, intervenor comments were filed objecting to full recovery of these foregone revenues. In March 2014, the PUCO issued an order in OPCo’s EDR filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals.deferrals which, as of June 30, 2014, is recorded in regulatory assets on the balance sheet. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement is scheduled forwas held in May 2014.

In addition, in the 2009 –- 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.

To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. As of March 31,June 30, 2014, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting that OPCo refund all collected pre-construction costs to Ohio ratepayers with interest.

42
Management cannot predict the outcome of this proceeding concerning the Ohio IGCC plant or what effect, if any, this proceeding 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

2012 Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In October 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of March 31,June 30, 2014, the net book value of Welsh Plant, Unit 2 was $86$85 million, before cost of removal, including materials and supplies inventory and CWIP.


55



Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase is approximately $52 million. In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling.  Thisruling and in April 2014, this order became finalfinal. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and appealable in April 2014.filed initial responses.

If any part of the PUCT order is overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs of Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

2013 Texas Transmission Cost Recovery Factor Filing

In December 2013,May 2014, SWEPCo filed an application with the PUCT to implement its initial transmission cost recovery factor (TCRF) requesting additional annual revenue of $10$15 million. The TCRF is designed to recover increases from the amounts included in SWEPCo’s Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC. SWEPCo’s application included Turk Plant transmission-related costs. In MarchJuly 2014, intervenors filed testimony with recommendations that included decreases ranging from $5 million to $14 million to the Administrative Law Judge (ALJ) dismissed this case without prejudice.  The ALJ concluded that SWEPCo’s application was premature asrequested annual revenue. A hearing at the PUCT had not completed its ruling onis scheduled for August 2014. An order is anticipated in the motions for rehearingfourth quarter of 2014. If the PUCT were to disallow any portion of the order in the SWEPCo Texas Base Rate Case in which the baseline values to be used in the TCRF, calculation would be established.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. The rates are subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant.  If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

2014 Louisiana Formula Rate Filing

In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC.  The filing included a $5 million annual increase to be effective August 2014.  SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a
43
purchase power agreement attributable to Louisiana customers.  These increases are subject to LPSC staff review.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC.  Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC.  As of June 30, 2014, SWEPCo has incurred $72 million in costs related to these projects.  SWEPCo will seek to recover these project costs

56


from customers through filings at the state commissions and FERC. These environmental projects could be impacted by pending carbon emission regulations.  As of June 30, 2014, the net book value of Welsh Plant, Units 1 and 3 was $297 million, before cost of removal, including materials and supplies inventory and CWIP.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 

APCo and WPCo Rate Matters

Plant Transfer

In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo.WPCo until APCo's West Virginia base rates are updated. See the "2014 West Virginia Base Rate Case" below. In April 2014, APCoAGR and WPCo also filed a request with the FERC for approval to transfer AGR’s one-half interest in the Mitchell Plant to WPCo. Upon transferIn June 2014, the FERC issued an order approving this request. Also in June 2014, an intervenor filed a motion to stay the proceeding at the WVPSC until alternatives to the acquisition of the Mitchell Plant have been explored. In accordance with a July 2014 order addressing the motion to WPCo, WPCo will no longer purchase power from AGR.stay, APCo filed supplemental testimony to address intervenor concerns. In July 2014, the WVPSC issued an order that modified the procedural schedule. A hearing at the WVPSC is scheduled for September 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

APCo IGCC Plant

As of March 31,June 30, 2014, 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.  In March 2014, APCo submitted a request to the Virginia SCC as part of the 2014 Virginia Biennial Base Rate Case to amortize the Virginia jurisdictional share of these costs over two years. In June 2014, APCo submitted a request to the WVPSC as part of the 2014 West Virginia Base Rate Case to amortize the West Virginia jurisdictional share of these costs over five years. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Transmission Rate Adjustment Clause (transmission RAC)

In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually to be effective May 2014. In March 2014, the Virginia SCC issued an order approving a stipulation agreement between APCo and the Virginia SCC staff increasing the transmission RAC revenues by $49 million annually, subject to true-up, effective May 2014. Pursuant to the order, the Virginia SCC staff will audit APCo’s transmission RAC under-recoveries and report its findings and recommendations in testimony in APCo’s next transmission RAC proceeding in 2015.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a biennial generation and distribution base rate biennial reviewcase with the Virginia SCC. In accordance with a Virginia statute, APCo did not request a change in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to changes in the expected service lives of various generating units and the extended recovery through 2040 of the net book value of certain planned 2015 plant retirements. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to certainIGCC and other deferred costs. A hearing at the Virginia SCC is scheduled for September 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


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2014 West Virginia Base Rate Case

In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $181 million, based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units. The filing also requested amortization of $89 million over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $45 million annually to recover total vegetation management costs. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

PSO Rate Matters

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years.

In April and May 2014, testimony was filed by the OCC Staffstaff and intervenors filed testimony with recommendations that included adjustments to annual base rates ranging from an increase of $16 million to a reduction of $22 million, primarily based upon the determination of depreciation rates and a return on common equity between 9.18% and 9.5%. Additionally, the
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recommendations did not support the advanced metering rider or the expansion of the transmission rider. In May 2014, PSO filed rebuttal testimony that included an updated annual base rate increase request of $42 million to reflect certain updated costs.

In June 2014, a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors was filed with the OCC. The parties to the stipulation recommended no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider would provide $7 million of revenues in 2014 and increases to $27 million in 2016. New depreciation rates are recommended for advanced metering investments and existing meters, to be effective November 2014. Further, the stipulation recommends a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring and for riders with an equity component. Additionally, the stipulation recommends recovery of regulatory assets for 2013 storms and regulatory case expenses. In July 2014, the Attorney General joined in the stipulation agreement. A hearing at the OCC is scheduled for Junewas held in July 2014. If the OCC were to disallow any portion of this base rate request,settlement agreement, 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% and adjusted the authorized annual increase in base rates to $92 million in March 2013. In March 2013,April 2014, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the order with the Indiana Court of Appeals.  In March 2014, the Indiana Court of Appeals upheld the February 2013 IURC order.  In April 2014, the OUCC filed an appeal to the Indiana Supreme Court related to the inclusion of a prepaid pension asset in rate base.base, which is approximately $7 million in annual revenues. If any part of the IURC order is overturned by the Indiana Supreme Court, it could reduce future net income and cash flows.flows and impact financial condition.


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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 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 March 31,June 30, 2014, I&M has incurred costs of $405$439 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC. In May 2014, the IURC issued a final order approving the LCM rider rates that were implemented in January 2014.

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

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

Tanners Creek Plant Units 1 - 4

In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations. In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas. I&M is currently recovering depreciation and a return on the net book value of the Tanners Creek Plant in base rates and plans to seek recovery of all of the plant’s retirement related costs in its next Indiana and Michigan base rate cases.

In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015. Upon the retirement of the Tanners Creek Plant, I&M proposesproposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant will be recovered over the remaining life of the Rockport Plant. I&M requested to have the impact of these new depreciation rates incorporated into the rates set in its next rate case.case where I&M will also seek continued recovery of a return on the net book value of the Tanners Creek Plant. The new depreciation rates are expected towould result in a decrease in I&M’s Michigan jurisdictional electric depreciation expense which I&M proposesproposed to implement in the month following a MPSC order in the revised depreciation case.order. A hearing at the MPSC is scheduled for September 2014.

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As of March 31,June 30, 2014, the net book value of the Tanners Creek Plant was $334$327 million, before cost of removal, including materials and supplies inventory and CWIP. If I&M is ultimately not permitted to fully recover its net book value of the Tanners Creek Plant and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition.


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KPCo Rate Matters

Plant Transfer

In October 2012, the AEP East Companies submitted several filings with the FERC.  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. KPCo also requested that costs related to the Big Sandy Plant, Unit 2 FGD project be established as a regulatory asset. As of March 31,June 30, 2014, the net book value of Big Sandy Plant, Unit 2 was $247$276 million, before cost of removal, including materials and supplies inventory and CWIP.

In October 2013, the KPSC issued an order approving a modified settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club. The modified settlement approved the transfer of a one-half interest in the Mitchell Plant to KPCo at net book value on December 31, 2013 with the limitation that the net book value of the Mitchell Plant transfer not exceed the amount to be determined by a WVPSC order. The WVPSC order was subsequently issued in December 2013, but the WVPSC deferred a decision on the transfer of the one-half interest in the Mitchell Plant to APCo. The settlement also included the implementation of an Asset Transfer Rider to collect $44 million annually effective January 2014, subject to true-up, and allowed KPCo to retain any off-system sales margins above the $15.3 million annual level in base rates. Additionally, the settlement allows for KPCo to file a Certificate of Public Convenience and Necessity to convert Big Sandy Plant, Unit 1 to natural gas, provided the cost is approximately $60 million, and addressed potential greenhouse gas initiatives on the Mitchell Plant. The settlement also approved recovery, including a return, of coal-related retirement costs related to Big Sandy Plant over 25 years when base rates are set in the next base rate case (no earlier than June 2015), but rejected KPCo’s request to defer FGD project costs for Big Sandy Plant, Unit 2. As a result of this order, in 2013, KPCo recorded a pretax regulatory disallowance of $33 million in Asset Impairments and Other Related Charges on the statement of income.  In December 2013, the Attorney General filed an appeal with the Franklin County Circuit Court.  In December 2013, KPCo filed motions with the Franklin County Circuit Court to dismiss the appeal.  A hearing on the motions to dismiss was held in January 2014.  In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed.

In December 2013, the Attorney General filed an appeal with the Franklin County Circuit Court. In May 2014, KPCo's motion to dismiss the appeal was denied. In May 2014, KPCo filed motions for reconsideration and clarification with the Franklin County Circuit Court. In June 2014, the motion for reconsideration was denied but the motion to clarify was granted, thereby limiting the appeal to the issues of law presented in the Attorney General's appeal. If any part of the KPSC order is overturned, it could reduce future net income and cash flows and impact financial condition.


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5.  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 2013 Annual Report should be read in conjunction with this report.

GUARANTEES

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

Letters of Credit

We enter into standby letters of credit with third parties.  As Parent, we issue all of these letters of credit in our ordinary course of business on behalf of our subsidiaries.  These letters of credit cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

We have two revolving credit facilities totaling $3.5 billion, under which we may issue up to $1.2 billion as letters
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of credit.  As of March 31,June 30, 2014, the maximum future payments for letters of credit issued under the revolving credit facilities were $130$49 million with maturities ranging from JuneAugust 2014 to AprilJune 2015.

In January 2014, we issued letters of credit under an $85 million uncommitted facility signed in October 2013. As of March 31,June 30, 2014, the maximum future payment for letters of credit issued under the uncommitted facility was $75$69 million with a maturity in July 2014.January 2015. An uncommitted facility gives the issuer of the facility the right to accept or decline each request we make under the facility.

We have $352$477 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $356$483 million.  The letters of credit have maturities ranging from July 2014March 2015 to MarchJuly 2017.

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 March 31,June 30, 2014, SWEPCo has collected approximately $62$63 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $46$47 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.


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Indemnifications and Other Guarantees

Contracts

We enter into severalcertain 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.  As of March 31,June 30, 2014, 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 March 31,June 30, 2014, the maximum potential loss for these lease agreements was approximately $21 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 isassignments 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$12 million and $15$14 million for
��
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I&M and SWEPCo, respectively, for the remaining railcars as of March 31,June 30, 2014.

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

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 generation 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 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

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approximately $8$7 million.  As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ.  We cannot predict the amount of additional cost, if any.

NUCLEAR CONTINGENCIES

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

OPERATIONAL CONTINGENCIES

Rockport Plant Litigation

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

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
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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.  That motion was denied.  We are considering seeking a review of this issue by the U.S. Supreme Court.   Defendants in these cases, including AEP, previously filed a petition seeking further review with the U.S. Supreme Court on the preemption issue, which is pending.issue. In June 2014, AEP filed a petition with the U.S. Supreme Court seeking review of the personal jurisdiction issue. In July 2014, the U.S. Supreme Court granted the defendants' previously filed petition for further review with the U.S. Supreme Court on the preemption issue.  We will continue to defend the cases.  We believe the provision we have is adequate. We are unable to determine a range of potential losses that are reasonably possible of occurring.


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Wage and Hours Lawsuit

In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act.  Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked.  Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs.  Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount.

In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action.  Notice was given to all class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. We will continue to defend the case. We are unable to determine a range of potential losses that are reasonably possible of occurring.

National Do Not Call Registry Lawsuit

In May 2014, AEP Energy was served with a complaint filed in the U.S. District Court for the Northern District of Illinois, alleging violations of the Telephone Consumer Protection Act (TCPA). The plaintiff alleges that he received telemarketing calls on behalf of AEP Energy despite having registered his telephone number on the National Do Not Call Registry. Plaintiff seeks to represent a class of persons who allegedly received such calls. Plaintiff seeks statutory damages under the TCPA on behalf of himself and the alleged class as well as injunctive relief. We will continue to defend this case. We are unable to determine a range of potential losses that are reasonably possible of occurring.


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6.  IMPAIRMENT

2013

Muskingum River Plant, Unit 5 (Generation & Marketing 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 the 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant.  Under the modification to the consent decree, we have 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, we 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 will retire the plant in 2015.


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7.  BENEFIT PLANS

Components of Net Periodic Benefit Cost

The following table providestables provide the components of our net periodic benefit cost (credit) for the plans for the three and six months ended March 31,June 30, 2014 and 2013:

  Other PostretirementPension Plans 
Other Postretirement
Benefit Plans
Pension Plans Benefit PlansThree Months Ended Three Months Ended
Three Months Ended March 31, Three Months Ended March 31,June 30, June 30,
2014  2013  2014  2013 2014 2013 2014 2013
(in millions)(in millions)
Service Cost$ 18  $ 17  $ 4  $ 6 $18
 $18
 $3
 $6
Interest Cost  55    50    17    18 56
 51
 17
 17
Expected Return on Plan Assets  (66)   (69)   (28)   (27)(65) (70) (28) (26)
Amortization of Prior Service Cost (Credit)  1    1    (17)   (17)
Amortization of Prior Service Credit—
 —
 (17) (18)
Amortization of Net Actuarial Loss  31    46    5    16 31
 46
 6
 16
Net Periodic Benefit Cost (Credit)$ 39  $ 45  $ (19) $ (4)$40
 $45
 $(19) $(5)
 Pension Plans 
Other Postretirement
Benefit Plans
 Six Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in millions)
Service Cost$36
 $35
 $7
 $12
Interest Cost111
 101
 34
 35
Expected Return on Plan Assets(131) (139) (56) (53)
Amortization of Prior Service Cost (Credit)1
 1
 (34) (35)
Amortization of Net Actuarial Loss62
 92
 11
 32
Net Periodic Benefit Cost (Credit)$79
 $90
 $(38) $(9)


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7.  8.  BUSINESS SEGMENTS

Our primary business is the generation, transmission and distribution of electricity. Within our Vertically Integrated Utilities 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.

During the fourth quarter of 2013, we changed the structure of our internal organization which resulted in a change in the composition of our reportable segments. In accordance with authoritative accounting guidance for segment reporting, prior period financial information has been recast in the financial statements and footnotes to be comparable to the current year presentation of reportable segments.

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

Vertically Integrated Utilities

·  Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

·  Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
·  OPCo purchases energy to serve standard service offer customers, and provides capacity for all connected load.

AEP Transmission Holdco

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

Generation & Marketing

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

AEP River Operations

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

The remainder of our activities is presented as Corporate and Other.  While not considered a reportable segment, Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’sParent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.


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The tables below present our reportable segment information for the three and six months ended March 31,June 30, 2014 and 2013 and balance sheet information as of March 31,June 30, 2014 and December 31, 2013.  These amounts include certain estimates and allocations where necessary.

       Transmission                   
    Vertically and AEP Generation    Corporate       
   Integrated Distribution Transmission & AEP Riverand OtherReconciling   
   Utilities Utilities Holdco Marketing Operations(a) Adjustments Consolidated
    (in millions)
Three Months Ended March 31, 2014                         
Revenues from:                         
  External Customers $ 2,549 (b)$ 1,161  $ 12  $ 821 (b)$ 146  $ 10  $ (51)(c) $ 4,648 
  Other Operating Segments   37 (b)  54    16    430 (b)  19    16    (572)    - 
Total Revenues $ 2,586  $ 1,215  $ 28  $ 1,251  $ 165  $ 26  $ (623)  $ 4,648 
                            
Net Income (Loss) $ 279  $ 97  $ 24  $ 163  $ 3  $ (5) $ -   $ 561 
                            
       Transmission                   
    Vertically and AEP Generation    Corporate       
   Integrated Distribution Transmission & AEP Riverand OtherReconciling   
   Utilities Utilities Holdco Marketing Operations(a) Adjustments Consolidated
    (in millions)
Three Months Ended March 31, 2013                         
Revenues from:                         
  External Customers $ 2,356  $ 1,090  $ 3  $ 258  $ 128  $ 5  $ (14)(c) $ 3,826 
  Other Operating Segments   159    44    5    662    5    13    (888)    - 
Total Revenues $ 2,515  $ 1,134  $ 8  $ 920  $ 133  $ 18  $ (902)  $ 3,826 
                            
Net Income (Loss) $ 181  $ 87  $ 12  $ 85  $ (2) $ 1  $ -   $ 364 
                          
     Transmission                   
  Vertically and AEP Generation   Corporate Reconciling    
  Integrated Distribution Transmission & AEP River and Other Adjustments    
  Utilities Utilities Holdco Marketing Operations (a) (d)  Consolidated
  (in millions)
March 31, 2014                         
Total Property, Plant and Equipment $ 37,923 $  12,339 $  1,842 $  8,302 $ 639  $ 321  $  (272)  $  61,094
Accumulated Depreciation and                         
  Amortization   12,424   3,382  13    3,460  197   176    (88)    19,564
Total Property, Plant and                         
   Equipment - Net $ 25,499 $  8,957 $  1,829 $  4,842 $ 442  $ 145  $  (184)  $  41,530
                           
Total Assets $ 32,997 $ 13,899 $ 2,460 $ 6,354 $659  $ 20,275 $ (19,606)(e) $ 57,038
                           
     Transmission                   
   Vertically and AEP Generation    Corporate Reconciling    
   Integrated Distribution Transmission & AEP River and Other Adjustments    
   Utilities Utilities Holdco Marketing Operations (a) (d)  Consolidated
   (in millions)
December 31, 2013                         
Total Property, Plant and Equipment $ 37,545 $ 12,143 $ 1,636 $ 8,277 $638  $315  $ (269)  $ 60,285
Accumulated Depreciation and                         
  Amortization   12,250   3,342   10   3,409  189   173    (85)    19,288
Total Property, Plant and                         
   Equipment - Net $ 25,295 $ 8,801 $ 1,626 $ 4,868 $449  $142  $ (184)  $ 40,997
                           
Total Assets $ 32,791 $ 14,165 $ 2,245 $ 6,426 $673  $ 19,645 $ (19,531)(e) $ 56,414
  Vertically Integrated Utilities
Transmission and Distribution Utilities
AEP Transmission Holdco
Generation
&
Marketing

AEP River Operations
Corporate and Other (a)
Reconciling Adjustments
Consolidated
  (in millions)
Three Months Ended 
 June 30, 2014		  
  
  
  
  
  
    
Revenues from:  
  
  
  
  
  
    
External Customers $2,236
(b)$1,064
 $21
 $573
(b)$140
 $10
 $—
(c)$4,044
Other Operating Segments 16
(b)70
 36
 340
(b)20
 12
 (494) —
Total Revenues $2,252
 $1,134
 $57
 $913
 $160
 $22
 $(494) $4,044

                
Net Income (Loss) $155
 $90
 $47
 $98
 $3
 $(2) $—
 $391
                 
  Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated
  (in millions)
Three Months Ended 
 June 30, 2013		  
  
  
  
  
  
    
Revenues from:  
  
  
  
  
  
    
External Customers $2,176
 $1,019
 $6
 $298
 $111
 $9
 $(37)(c)$3,582
Other Operating Segments 126
 45
 13
 594
 6
 12
 (796) —
Total Revenues $2,302
 $1,064
 $19
 $892
 $117
 $21
 $(833) $3,582
                 
Net Income (Loss) $153
 $75
 $19
 $(9) $(9) $110
 $—
 $339


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  Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated
  (in millions)
Six Months Ended 
 June 30, 2014		  
  
    
  
  
  
  
Revenues from:  
  
    
  
  
  
  
External Customers $4,785
(b)$2,225
 $33
 $1,394
(b)$286
 $20
 $(51)(c)$8,692
Other Operating Segments 53
(b)124
 52
 770
(b)39
 28
 (1,066) —
Total Revenues $4,838
 $2,349
 $85
 $2,164
 $325
 $48
 $(1,117) $8,692
                 
Net Income (Loss) $434
 $187
 $71
 $261
 $6
 $(7) $—
 $952
                 
  Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated
  (in millions)
Six Months Ended 
 June 30, 2013		  
  
    
  
  
  
  
Revenues from:  
  
    
  
  
  
  
External Customers $4,532
 $2,109
 $9
 $556
 $239
 $14
 $(51)(c)$7,408
Other Operating Segments 285
 89
 18
 1,256
 11
 25
 (1,684) —
Total Revenues $4,817
 $2,198
 $27
 $1,812
 $250
 $39
 $(1,735) $7,408
                 
Net Income (Loss) $334
 $162
 $31
 $76
 $(11) $111
 $—
 $703


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  Vertically Integrated Utilities
Transmission and Distribution Utilities
AEP Transmission Holdco
Generation
&
Marketing

AEP River Operations
Corporate and Other (a)
Reconciling
Adjustments

Consolidated
  (in millions)
June 30, 2014  
  
  
  
    
  
  
Total Property, Plant and Equipment $38,390
 $12,554
 $2,079
 $8,345
 $640
 $329
 $(272)(d)$62,065
Accumulated Depreciation and Amortization 12,562
 3,407
 16
 3,514
 204
 181
 (92)(d)19,792
Total Property Plant and Equipment - Net $25,828
 $9,147
 $2,063
 $4,831
 $436
 $148
 $(180)(d)$42,273
                 
Total Assets $33,024
 $13,859
 $2,702
 $6,301
 $638
 $20,379
 $(19,283)(d) (e)$57,620
                 
Long-term Debt Due Within One Year:                
Affiliated $131
 $—
 $—
 $125
 $—
 $—
 $(256) $—
Non-Affiliated 1,382
 448
 —
 687
 3
 4
 —
 2,524
                 
Long-term Debt:                
Affiliated 20
 —
 —
 32
 —
 —
 (52) —
Non-Affiliated 8,445
 5,306
 689
 239
 82
 840
 —
 15,601
                 
Total Long-term Debt $9,978
 $5,754
 $689
 $1,083
 $85
 $844
 $(308) $18,125
                 
  Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 AEP River Operations Corporate and Other (a) Reconciling
Adjustments		 Consolidated
  (in millions)
December 31, 2013  
  
  
  
    
  
  
Total Property, Plant and Equipment $37,545
 $12,143
 $1,636
 $8,277
 $638
 $315
 $(269)(d)$60,285
Accumulated Depreciation and Amortization 12,250
 3,342
 10
 3,409
 189
 173
 (85)(d)19,288
Total Property Plant and Equipment - Net $25,295
 $8,801
 $1,626
 $4,868
 $449
 $142
 $(184)(d)$40,997
                 
Total Assets $32,791
 $14,165
 $2,245
 $6,426
 $673
 $19,645
 $(19,531)(d) (e)$56,414
                 
Long-term Debt Due Within One Year:                
Affiliated $—
 $—
 $—
 $179
 $5
 $—
 $(184) $—
Non-Affiliated 720
 697
 —
 126
 2
 4
 —
 1,549
                 
Long-term Debt:                
Affiliated 151
 —
 —
 118
 10
 —
 (279) —
Non-Affiliated 9,265
 5,360
 620
 664
 83
 836
 —
 16,828
                 
Total Long-term Debt $10,136
 $6,057
 $620
 $1,087
 $100
 $840
 $(463) $18,377

(a)Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’sParent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
(b)Includes the impact of the corporate separation of OPCo’sOPCo's generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014.
(c)Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation.
(d)Includes eliminations due to an intercompany capital lease.
(e)Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’sAEP's investments in subsidiary companies.


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51


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

The following table represents the gross notional volume of our outstanding derivative contracts as of March 31,June 30, 2014 and December 31, 2013:

Notional Volume of Derivative Instruments
          
   Volume  
   March 31, December 31, Unit of
  2014  2013  Measure
Primary Risk Exposure (in millions) 
Commodity:        
 Power   320    406  MWhs
 Coal   4    4  Tons
 Natural Gas   123    127  MMBtus
 Heating Oil and Gasoline   4    6  Gallons
 Interest Rate $ 192  $ 191  USD
          
Interest Rate and Foreign Currency $ 819  $ 820  USD
Notional Volume of Derivative Instruments
  Volume  
  June 30,
2014		 December 31,
2013		 
Unit of
Measure
Primary Risk Exposure (in millions)  
Commodity:    
  
Power 430
 406
 MWhs
Coal 3
 4
 Tons
Natural Gas 116
 127
 MMBtus
Heating Oil and Gasoline 5
 6
 Gallons
Interest Rate $176
 $191
 USD
       
Interest Rate and Foreign Currency $819
 $820
 USD


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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.

52
Cash Flow Hedging Strategies

We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“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. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014. During the three and six months ended March 31,June 30, 2013, we designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As ofIn March 31, 2014, these contracts will bewere grouped as “Commodity”"Commodity" with other risk management activities. We do not hedge all fuel price risk.

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

At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers. In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. We do not hedge all foreign currency exposure.

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

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’scontract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash

72


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 March 31,June 30, 2014 and December 31, 2013 condensed balance sheets, we netted $19$26 million and $4 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $17$1 million and $13 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

53
The following tables represent the gross fair value impact of our derivative activity on our condensed balance sheets as of March 31,June 30, 2014 and December 31, 2013:

Fair Value of Derivative Instruments
March 31, 2014
  
             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 $ 442  $ 23  $ 4  $ 469  $ (344) $ 125 
Long-term Risk Management Assets   342    5    -    347    (81)   266 
Total Assets   784    28    4    816    (425)   391 
                    
Current Risk Management Liabilities   384    16    1    401    (341)   60 
Long-term Risk Management Liabilities   205    4    13    222    (85)   137 
Total Liabilities   589    20    14    623    (426)   197 
                    
Total MTM Derivative Contract Net                  
 Assets (Liabilities) $ 195  $ 8  $ (10) $ 193  $ 1  $ 194 
                    
Fair Value of Derivative Instruments
December 31, 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 LiabilitiesFinancial Financial
Balance Sheet Location Commodity (a) Commodity (a) Currency (a) Recognized Position (b) Position (c)
   (in millions)
Current Risk Management Assets $ 347  $ 12  $ 4  $ 363  $ (203) $ 160 
Long-term Risk Management Assets   368    3    -    371    (74)   297 
Total Assets   715    15    4    734    (277)   457 
                    
Current Risk Management Liabilities   292    11    1    304    (214)   90 
Long-term Risk Management Liabilities   237    3    15    255    (78)   177 
Total Liabilities   529    14    16    559    (292)   267 
                    
Total MTM Derivative Contract Net                  
 Assets (Liabilities) $ 186  $ 1  $ (12) $ 175  $ 15  $ 190 
Fair Value of Derivative Instruments
June 30, 2014
  
Risk
Management
Contracts
 Hedging Contracts 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) 
Interest Rate
and Foreign
Currency (a)
   
  (in millions)
Current Risk Management Assets $454
 $28
 $4
 $486
 $(340) $146
Long-term Risk Management Assets 314
 5
 —
 319
 (95) 224
Total Assets 768
 33
 4
 805
 (435) 370
             
Current Risk Management Liabilities 372
 20
 1
 393
 (333) 60
Long-term Risk Management Liabilities 182
 2
 10
 194
 (79) 115
Total Liabilities 554
 22
 11
 587
 (412) 175
             
Total MTM Derivative Contract Net Assets (Liabilities) $214
 $11
 $(7) $218
 $(23) $195
             
Fair Value of Derivative Instruments
December 31, 2013
             
  
Risk
Management
Contracts
 Hedging Contracts Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized		 Gross
Amounts
Offset in the
Statement of
Financial
Position (b)		 Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) Interest Rate
and Foreign
Currency (a)		   
  (in millions)
Current Risk Management Assets $347
 $12
 $4
 $363
 $(203) $160
Long-term Risk Management Assets 368
 3
 —
 371
 (74) 297
Total Assets 715
 15
 4
 734
 (277) 457
             
Current Risk Management Liabilities 292
 11
 1
 304
 (214) 90
Long-term Risk Management Liabilities 237
 3
 15
 255
 (78) 177
Total Liabilities 529
 14
 16
 559
 (292) 267
             
Total MTM Derivative Contract Net Assets (Liabilities) $186
 $1
 $(12) $175
 $15
 $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.


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The table below presents our activity of derivative risk management contracts for the three and six months ended March 31,June 30, 2014 and 2013:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended March 31, 2014 and 2013
       
Location of Gain (Loss) 2014   2013 
  (in millions)
Vertically Integrated Utilities Revenues $ 18  $ 6 
Generation & Marketing Revenues   32    16 
Regulatory Assets (a)   -    2 
Regulatory Liabilities (a)   89    (6)
Total Gain on Risk Management Contracts $ 139  $ 18 
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three and Six Months Ended June 30, 2014 and 2013
  Three Months Ended June 30, Six Months Ended June 30,
Location of Gain (Loss) 2014 2013 2014 2013
  (in millions)
Vertically Integrated Utilities Revenues $4
 $4
 $22
 $10
Generation & Marketing Revenues 16
 17
 48
 33
Regulatory Assets (a) —
 (8) —
 (6)
Regulatory Liabilities (a) 29
 4
 118
 (2)
Total Gain on Risk Management Contracts $49
 $17
 $188
 $35

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

54
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 March 31,June 30, 2014, we recognized gains of $2 million and $4 million, respectively, on our hedging instruments and offsetting losses of $2 million and $4 million, respectively, on our long-term debt.  During the three and six months ended March 31,June 30, 2013, we recognized losses of $1$11 million and $12 million, respectively, on our hedging instruments and offsetting gains of $1$11 million and $12 million, respectively, on our long-term debt.  During the three and six months ended March 31,June 30, 2014 and 2013, hedge ineffectiveness was immaterial.


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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 March 31,June 30, 2014 and 2013, 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 March 31,June 30, 2013, we designated heating oil and gasoline derivatives as cash flow hedges. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014.

55
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 March 31,June 30, 2014 and 2013, 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 March 31,June 30, 2014 and 2013, we did not designate any foreign currency derivatives as cash flow hedges.

During the three and six months ended March 31,June 30, 2014 and 2013, 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 March 31,June 30, 2014 and 2013, see Note 3.


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Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31,June 30, 2014 and December 31, 2013 were:

Impact of Cash Flow Hedges on the Condensed Balance Sheet
March 31, 2014
            
       Interest Rate   
       and Foreign   
    Commodity Currency Total
    (in millions)
Hedging Assets (a) $ 13  $ -  $ 13 
Hedging Liabilities (a)   5    2    7 
AOCI Gain (Loss) Net of Tax   4    (22)   (18)
Portion Expected to be Reclassified to Net         
 Income During the Next Twelve Months   3    (4)   (1)
            
Impact of Cash Flow Hedges on the Condensed Balance Sheet
December 31, 2013
            
       Interest Rate   
       and Foreign   
    Commodity Currency Total
    (in millions)
Hedging Assets (a) $ 7  $ -  $ 7 
Hedging Liabilities (a)   6    2    8 
AOCI Gain (Loss) Net of Tax   -    (23)   (23)
Portion Expected to be Reclassified to Net         
 Income During the Next Twelve Months   -    (4)   (4)
Impact of Cash Flow Hedges on the Condensed Balance Sheet
June 30, 2014
 Commodity 
Interest Rate
and Foreign
Currency
 Total
 (in millions)
Hedging Assets (a)$15
 $—
 $15
Hedging Liabilities (a)4
 2
 6
AOCI Gain (Loss) Net of Tax6
 (21) (15)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months4
 (3) 1
      
Impact of Cash Flow Hedges on the Condensed Balance Sheet
December 31, 2013
      
 Commodity Interest Rate
and Foreign
Currency		 Total
 (in millions)
Hedging Assets (a)$7
 $—
 $7
Hedging Liabilities (a)6
 2
 8
AOCI Loss Net of Tax—
 (23) (23)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months—
 (4) (4)

(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 March 31,June 30, 2014, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions was 4142 months.

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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.


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Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs), a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, and guaranties for contractual obligations, we are obligated to post an additional amount of collateral if our credit ratings decline below a specified rating threshold. 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 a specified rating threshold that would require the posting of additional collateral. 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 and guaranties for contractual obligations if our credit ratings had declined below a specified rating threshold and (c) how much was attributable to RTO and ISO activities as of March 31,June 30, 2014 and December 31, 2013:

  March 31, December 31,
  2014  2013 June 30,
2014		 December 31,
2013
  (in millions)(in millions)
Liabilities for Derivative Contracts with Credit Downgrade TriggersLiabilities for Derivative Contracts with Credit Downgrade Triggers $ 2  $ 3 $1
 $3
Amount of Collateral AEP Subsidiaries Would Have Been     
Required to Post  144    33 
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post167
 33
Amount Attributable to RTO and ISO ActivitiesAmount Attributable to RTO and ISO Activities  38    28 54
 28

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 March 31,June 30, 2014 and December 31, 2013:

 March 31, December 31,
 2014  2013 
 (in millions)June 30,
2014		 December 31,
2013
Liabilities for Contracts with Cross Default Provisions Prior to Contractual     
Netting Arrangements $ 225  $ 293 
(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements$201
 $293
Amount of Cash Collateral Posted  -    1 —
 1
Additional Settlement Liability if Cross Default Provision is Triggered  177    235 141
 235


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9.  10.  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 amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors. Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to AEP Energy Supply’s President and Vice President.

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

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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
58
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 March 31,June 30, 2014 and December 31, 2013 are summarized in the following table:

  March 31, 2014 December 31, 2013
  Book Value Fair Value Book Value Fair Value
  (in millions)
Long-term Debt $ 18,087  $ 19,738  $ 18,377  $ 19,672 
 June 30, 2014 December 31, 2013
 Book Value Fair Value Book Value Fair Value
 (in millions)
Long-term Debt$18,125
 $20,284
 $18,377
 $19,672

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:

   March 31, 2014
     Gross Gross Estimated
      Unrealized Unrealized  Fair June 30, 2014
Other Temporary InvestmentsOther Temporary Investments Cost Gains Losses Value Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Estimated
Fair
Value
   (in millions) (in millions)
Restricted Cash (a)Restricted Cash (a) $ 206  $ -  $ -  $ 206  $272
 $—
 $—
 $272
Fixed Income Securities:           
Mutual Funds  80    -    -    80 
Fixed Income Securities - Mutual Funds 80
 —
 —
 80
Equity Securities - Mutual FundsEquity Securities - Mutual Funds   13    11    -    24  13
 12
 —
 25
Total Other Temporary InvestmentsTotal Other Temporary Investments $ 299  $ 11  $ -  $ 310  $365
 $12
 $—
 $377
             
   December 31, 2013
     Gross Gross Estimated        
      Unrealized Unrealized  Fair December 31, 2013
Other Temporary InvestmentsOther Temporary Investments Cost Gains Losses Value Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Estimated
Fair
Value
   (in millions) (in millions)
Restricted Cash (a)Restricted Cash (a) $ 250  $ -  $ -  $ 250  $250
 $—
 $—
 $250
Fixed Income Securities:           
Mutual Funds  80    -    -    80 
Fixed Income Securities - Mutual Funds 80
 —
 —
 80
Equity Securities - Mutual FundsEquity Securities - Mutual Funds   12    11    -    23  12
 11
 —
 23
Total Other Temporary InvestmentsTotal Other Temporary Investments $ 342  $ 11  $ -  $ 353  $342
 $11
 $—
 $353
             
(a)Primarily represents amounts held for the repayment of debt.

(a)Primarily represents amounts held for the repayment of debt.


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59


The following table provides the activity for our fixed income and equity securities within Other Temporary Investments for the three and six months ended March 31,June 30, 2014 and 2013:

Three Months Ended March 31,Three Months Ended June 30, Six Months Ended June 30,
2014  2013 2014 2013 2014 2013
(in millions)(in millions)
Proceeds from Investment Sales$ -  $ - $—
 $—
 $—
 $—
Purchases of Investments  1    11 —
 —
 1
 11
Gross Realized Gains on Investment Sales  -    - —
 —
 —
 —
Gross Realized Losses on Investment Sales  -    - —
 —
 —
 —

As of March 31,June 30, 2014 and December 31, 2013, we had no Other Temporary Investments with an unrealized loss position.  As of March 31,June 30, 2014, fixed income securities were primarily debt based mutual funds with short and intermediate maturities.  Mutual funds may be sold and do not contain maturity dates.

For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and six months ended March 31,June 30, 2014 and 2013, see Note 3.

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

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

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

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

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value.  I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose.  Other-than-temporary impairments for investments in both 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.


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60


The following is a summary of nuclear trust fund investments as of March 31,June 30, 2014 and December 31, 2013:

  March 31, 2014 December 31, 2013
  Estimated Gross Other-Than- Estimated Gross Other-Than-
 FairUnrealizedTemporaryFairUnrealizedTemporaryJune 30, 2014 December 31, 2013
 ValueGainsImpairmentsValueGainsImpairments
Estimated
Fair
Value
 
Gross
Unrealized
Gains
 
Other-Than-
Temporary
Impairments
 
Estimated
Fair
Value
 
Gross
Unrealized
Gains
 
Other-Than-
Temporary
Impairments
  (in millions)(in millions)
Cash and Cash EquivalentsCash and Cash Equivalents $ 12  $ -  $ -  $ 19  $ -  $ - $15
 $—
 $—
 $19
 $—
 $—
Fixed Income Securities:Fixed Income Securities:             
  
  
    
  
United States Government  606   31   (4)  609   26   (4)
Corporate Debt  43   4   (1)  37   2   (1)
State and Local Government   281    1    -    255    1    - 
  Subtotal Fixed Income Securities  930   36   (5)  901   29   (5)
United States Government580
 37
 (26) 609
 26
 (4)
Corporate Debt47
 4
 (1) 37
 2
 (1)
State and Local Government309
 1
 (1) 255
 1
 —
Subtotal Fixed Income Securities936
 42
 (28) 901
 29
 (5)
Equity Securities - DomesticEquity Securities - Domestic   1,020    514    (80)   1,012    506    (82)1,068
 557
 (79) 1,012
 506
 (82)
Spent Nuclear Fuel and            
Decommissioning Trusts $ 1,962  $ 550  $ (85) $ 1,932  $ 535  $ (87)
Spent Nuclear Fuel and Decommissioning Trusts$2,019
 $599
 $(107) $1,932
 $535
 $(87)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended March 31,June 30, 2014 and 2013:

Three Months Ended March 31,Three Months Ended June 30, Six Months Ended June 30,
2014  2013 2014 2013 2014 2013
(in millions)(in millions)
Proceeds from Investment Sales$ 148  $ 168 $335
 $217
 $483
 $385
Purchases of Investments  164    185 345
 227
 509
 412
Gross Realized Gains on Investment Sales  8    3 9
 9
 17
 12
Gross Realized Losses on Investment Sales  1    2 8
 8
 9
 10

The adjusted cost of fixed income securities was $894 million and $872 million as of March 31,June 30, 2014 and December 31, 2013, respectively.  The adjusted cost of equity securities was $506$511 million and $506 million as of March 31,June 30, 2014 and December 31, 2013, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31,June 30, 2014 was as follows:

Fair Value of
Fixed Income
Securities
(in millions)
Within 1 year$ 82 
1 year – 5 years 386 
5 years – 10 years 193 
After 10 years 269 
Total$ 930 
 
Fair Value of
Fixed Income
Securities
 (in millions)
Within 1 year$39
1 year – 5 years414
5 years – 10 years208
After 10 years275
Total$936

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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 March 31,June 30, 2014 and December 31, 2013.  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
March 31, 2014
            
   Level 1 Level 2 Level 3 Other Total
Assets:(in millions)
                 
Cash and Cash Equivalents (a)$ 16  $ 1  $ -  $ 275  $ 292 
                 
Other Temporary Investments              
Restricted Cash (a)  187    7    -    12    206 
Fixed Income Securities:              
 Mutual Funds  80    -    -    -    80 
Equity Securities - Mutual Funds (b)  24    -    -    -    24 
Total Other Temporary Investments  291    7    -    12    310 
                 
Risk Management Assets              
Risk Management Commodity Contracts (c) (d)  20    586    128    (364)   370 
Cash Flow Hedges:              
 Commodity Hedges (c)  -    21    2    (10)   13 
Fair Value Hedges  -    2    -    2    4 
De-designated Risk Management Contracts (e)  -    -    -    4    4 
Total Risk Management Assets  20    609    130    (368)   391 
                 
Spent Nuclear Fuel and Decommissioning Trusts              
Cash and Cash Equivalents (f)  3    -    -    9    12 
Fixed Income Securities:              
 United States Government  -    606    -    -    606 
 Corporate Debt  -    43    -    -    43 
 State and Local Government  -    281    -    -    281 
  Subtotal Fixed Income Securities  -    930    -    -    930 
Equity Securities - Domestic (b)  1,020    -    -    -    1,020 
Total Spent Nuclear Fuel and Decommissioning Trusts  1,023    930    -    9    1,962 
                 
Total Assets$ 1,350  $ 1,547  $ 130  $ (72) $ 2,955 
                 
Liabilities:              
                 
Risk Management Liabilities              
Risk Management Commodity Contracts (c) (d)$ 30  $ 485  $ 25  $ (362) $ 178 
Cash Flow Hedges:              
 Commodity Hedges (c)  -    15    -    (10)   5 
 Interest Rate/Foreign Currency Hedges  -    2    -    -    2 
Fair Value Hedges  -    10    -    2    12 
Total Risk Management Liabilities$ 30  $ 512  $ 25  $ (370) $ 197 
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Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2014
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Cash and Cash Equivalents (a) $15
 $1
 $—
 $174
 $190
           
Other Temporary Investments          
Restricted Cash (a) 251
 10
 —
 11
 272
Fixed Income Securities - Mutual Funds 80
 —
 —
 —
 80
Equity Securities - Mutual Funds (b) 25
 —
 —
 —
 25
Total Other Temporary Investments
 356
 10
 —
 11
 377
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (d) 15
 585
 148
 (399) 349
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (c) —
 26
 7
 (18) 15
Fair Value Hedges —
 1
 —
 3
 4
De-designated Risk Management Contracts (e) —
 —
 —
 2
 2
Total Risk Management Assets 15
 612
 155
 (412) 370
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (f) 4
 —
 —
 11
 15
Fixed Income Securities:  
  
  
  
  
United States Government —
 580
 —
 —
 580
Corporate Debt —
 47
 —
 —
 47
State and Local Government —
 309
 —
 —
 309
Subtotal Fixed Income Securities —
 936
 —
 —
 936
Equity Securities - Domestic (b) 1,068
 —
 —
 —
 1,068
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,072
 936
 —
 11
 2,019
           
Total Assets $1,458
 $1,559
 $155
 $(216) $2,956
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (d) $26
 $485
 $23
 $(374) $160
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (c) —
 22
 —
 (18) 4
Interest Rate/Foreign Currency Hedges —
 2
 —
 —
 2
Fair Value Hedges —
 6
 —
 3
 9
Total Risk Management Liabilities $26
 $515
 $23
 $(389) $175


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62



Assets and Liabilities Measured at Fair Value on a Recurring Basis
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
            
   Level 1 Level 2 Level 3 Other Total
Assets:(in millions)
                 
Cash and Cash Equivalents (a)$ 16  $ 1  $ -  $ 101  $ 118 
                 
Other Temporary Investments              
Restricted Cash (a)  231    8    -    11    250 
Fixed Income Securities:              
 Mutual Funds  80    -    -    -    80 
Equity Securities - Mutual Funds (b)  23    -    -    -    23 
Total Other Temporary Investments  334    8    -    11    353 
                 
Risk Management Assets              
Risk Management Commodity Contracts (c) (g)  22    549    142    (273)   440 
Cash Flow Hedges:              
 Commodity Hedges (c)  -    15    -    (8)   7 
Fair Value Hedges  -    1    -    3    4 
De-designated Risk Management Contracts (e)  -    -    -    6    6 
Total Risk Management Assets  22    565    142    (272)   457 
                 
Spent Nuclear Fuel and Decommissioning Trusts              
Cash and Cash Equivalents (f)  8    -    -    11    19 
Fixed Income Securities:              
 United States Government  -    609    -    -    609 
 Corporate Debt  -    37    -    -    37 
 State and Local Government  -    255    -    -    255 
  Subtotal Fixed Income Securities  -    901    -    -    901 
Equity Securities - Domestic (b)  1,012    -    -    -    1,012 
Total Spent Nuclear Fuel and Decommissioning Trusts  1,020    901    -    11    1,932 
                 
Total Assets$ 1,392  $ 1,475  $ 142  $ (149) $ 2,860 
                 
Liabilities:              
                 
Risk Management Liabilities              
Risk Management Commodity Contracts (c) (g)$ 30  $ 475  $ 22  $ (282) $ 245 
Cash Flow Hedges:              
 Commodity Hedges (c)  -    11    3    (8)   6 
 Interest Rate/Foreign Currency Hedges  -    2    -    -    2 
Fair Value Hedges  -    11    -    3    14 
Total Risk Management Liabilities$ 30  $ 499  $ 25  $ (287) $ 267 
December 31, 2013
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Cash and Cash Equivalents (a) $16
 $1
 $—
 $101
 $118
           
Other Temporary Investments          
Restricted Cash (a) 231
 8
 —
 11
 250
Fixed Income Securities - Mutual Funds 80
 —
 —
 —
 80
Equity Securities - Mutual Funds (b) 23
 —
 —
 —
 23
Total Other Temporary Investments
 334
 8
 —
 11
 353
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) 22
 549
 142
 (273) 440
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (c) —
 15
 —
 (8) 7
Fair Value Hedges —
 1
 —
 3
 4
De-designated Risk Management Contracts (e) —
 —
 —
 6
 6
Total Risk Management Assets 22
 565
 142
 (272) 457
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (f) 8
 —
 —
 11
 19
Fixed Income Securities:  
  
  
  
  
United States Government —
 609
 —
 —
 609
Corporate Debt —
 37
 —
 —
 37
State and Local Government —
 255
 —
 —
 255
Subtotal Fixed Income Securities —
 901
 —
 —
 901
Equity Securities - Domestic (b) 1,012
 —
 —
 —
 1,012
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,020
 901
 —
 11
 1,932
           
Total Assets $1,392
 $1,475
 $142
 $(149) $2,860
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $30
 $475
 $22
 $(282) $245
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (c) —
 11
 3
 (8) 6
Interest Rate/Foreign Currency Hedges —
 2
 —
 —
 2
Fair Value Hedges —
 11
 —
 3
 14
Total Risk Management Liabilities $30
 $499
 $25
 $(287) $267

(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 March 31,June 30, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $2$1 million in 2014, $(11)($11) million in periods 2015-2017 and $(1)($1) million in periods 2018-2019;  Level 2 matures $32$21 million in 2014, $56$65 million in periods 2015-2017, $8$10 million in periods 2018-2019 and $5$4 million in periods 2020-2030;  Level 3 matures $15$42 million in 2014, $49$45 million in periods 2015-2017, $16$14 million in periods 2018-2019 and $23$24 million in periods 2020-2030.  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, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $4 million in 2014, $(11)($11) million in periods 2015-2017 and $(1)($1) million in periods 2018-2019;  Level 2 matures $25 million in 2014, $37 million in periods 2015-2017, $7 million in periods 2018-2019 and $5 million in periods 2020-2030;  Level 3 matures $27 million in 2014, $60 million in periods 2015-2017, $14 million in periods 2018-2019 and $19 million in periods 2020-2030.  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 March 31,June 30, 2014 and 2013.

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63

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 March 31, 2014Assets (Liabilities)
(in millions)
Balance as of December 31, 2013$ 117 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 84 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date (a) (10)
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 9 
Purchases, Issuances and Settlements (c) (100)
Transfers into Level 3 (d) (e) (4)
Transfers out of Level 3 (e) (f) (2)
Changes in Fair Value Allocated to Regulated Jurisdictions (g) 11 
Balance as of March 31, 2014$ 105 
Three Months Ended June 30, 2014 
Net Risk Management
Assets (Liabilities)
  (in millions)
Balance as of March 31, 2014 $105
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (14)
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 6
Purchases, Issuances and Settlements (c) (2)
Transfers into Level 3 (d) (e) 5
Transfers out of Level 3 (e) (f) (6)
Changes in Fair Value Allocated to Regulated Jurisdictions (g) 38
Balance as of June 30, 2014 $132

Net Risk Management
Three Months Ended March 31, 2013Assets (Liabilities)
(in millions)
Balance as of December 31, 2012$ 86 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (4)
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 1 
Purchases, Issuances and Settlements (c) (6)
Transfers into Level 3 (d) (e) 6 
Transfers out of Level 3 (e) (f) - 
Changes in Fair Value Allocated to Regulated Jurisdictions (g) (2)
Balance as of March 31, 2013$ 76 
Three Months Ended June 30, 2013 Net Risk Management
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

Six Months Ended June 30, 2014 Net Risk Management
Assets (Liabilities)
  (in millions)
Balance as of December 31, 2013 $117
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 82
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) (9)
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 14
Purchases, Issuances and Settlements (c) (102)
Transfers into Level 3 (d) (e) 1
Transfers out of Level 3 (e) (f) (7)
Changes in Fair Value Allocated to Regulated Jurisdictions (g) 36
Balance as of June 30, 2014 $132


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Six Months Ended June 30, 2013 Net Risk Management
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
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

(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.


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64


The following tables quantify the significant unobservable inputs used in developing the fair value of our Level 3 positions as of March 31,June 30, 2014 and December 31, 2013:

Significant Unobservable Inputs
March 31, 2014
                 
  Fair Value Valuation Significant Input/Range
 Assets LiabilitiesTechniqueUnobservable Input Low High
  (in millions)          
Energy Contracts $ 116  $ 23  Discounted Cash Flow  Forward Market Price (a)  $ 1.45  $ 131.46 
          Counterparty Credit Risk (b)  315 
FTRs   14    2  Discounted Cash Flow  Forward Market Price (a)    (5.05)   9.17 
Total $ 130  $ 25           
Significant Unobservable Inputs
June 30, 2014
     Significant Input/Range
 Fair ValueValuation Unobservable     Weighted
 Assets LiabilitiesTechnique Input Low High Average
 (in millions)          
Energy Contracts$116
 $22
 Discounted Cash Flow  Forward Market Price (a)  $10.71
 $110.67
 $50.44
  
  
   Counterparty Credit Risk (b)  251
FTRs39
 1
 Discounted Cash Flow  Forward Market Price (a)  (14.63) 9.69
 0.97
Total$155
 $23
      
  
  

Significant Unobservable Inputs
December 31, 2013
                 
  Fair Value Valuation Significant Input/Range
 Assets LiabilitiesTechniqueUnobservable Input Low High
  (in millions)          
Energy Contracts $ 132  $ 22  Discounted Cash Flow  Forward Market Price (a)  $ 11.42  $ 120.72 
          Counterparty Credit Risk (b)  316 
FTRs   10    3  Discounted Cash Flow  Forward Market Price (a)    (5.10)   10.44 
Total $ 142  $ 25           
Significant Unobservable Inputs
December 31, 2013
     Significant  
 Fair ValueValuation Unobservable Input/Range
 Assets LiabilitiesTechnique Input Low High
 (in millions)        
Energy Contracts$132
 $22
 Discounted Cash Flow  Forward Market Price (a)  $11.42
 $120.72
  
  
   Counterparty Credit Risk (b)  316
FTRs10
 3
 Discounted Cash Flow  Forward Market Price (a)  (5.10) 10.44
Total$142
 $25
      
  

(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.

The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs as of June 30, 2014:

Sensitivity of Fair Value Measurements
June 30, 2014
Significant Unobservable InputPositionChange in Input
Impact on Fair Value
Measurement
Forward Market PriceBuyIncrease (Decrease)Higher (Lower)
Forward Market PriceSellIncrease (Decrease)Lower (Higher)
Counterparty Credit RiskLossIncrease (Decrease)Higher (Lower)
Counterparty Credit RiskGainIncrease (Decrease)Lower (Higher)



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10.  11.  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 IRS examination of years 2011 and 2012 started in April 2014. 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. We are currently under examination in several state and local jurisdictions.  However, it is possible that we have filed tax returns with positions that may be challenged by these tax authorities.  We believe that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income.  We are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.



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65


11.  12.  FINANCING ACTIVITIES

Long-term Debt

The following table details long-term debt outstanding as of March 31,June 30, 2014 and December 31, 2013:

Type of Debt March 31, 2014 December 31, 2013 June 30, 2014 December 31, 2013
 (in millions) (in millions)
Senior Unsecured Notes $ 11,571  $ 11,799  $11,901
 $11,799
Pollution Control Bonds  1,932    1,932  1,963
 1,932
Notes Payable  342    369  310
 369
Securitization Bonds  2,574    2,686  2,547
 2,686
Spent Nuclear Fuel Obligation (a)  265    265  265
 265
Other Long-term Debt  1,434    1,360  1,169
 1,360
Fair Value of Interest Rate Hedges  (7)   (9) (5) (9)
Unamortized Discount, Net   (24)   (25) (25) (25)
Total Long-term Debt Outstanding   18,087    18,377  18,125
 18,377
Long-term Debt Due Within One Year   1,612    1,549  2,524
 1,549
Long-term Debt $ 16,475  $ 16,828  $15,601
 $16,828

(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal.  The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983.  Trust fund assets related to this obligation were $309 million and $309 million as of March 31,June 30, 2014 and December 31, 2013, 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 threesix months of 2014 are shown in the tables below:

    Principal  Interest  
CompanyCompany Type of Debt Amount  Rate Due Date Type of Debt 
Principal
Amount
 
Interest
Rate
 Due Date
Issuances:Issuances:  (in millions) (%)     (in millions) (%)  
APCo Senior Unsecured Notes $300
 4.40 2044
I&M Pollution Control Bonds 100
 1.75 2018
PSOPSO Other Long-term Debt $ 50   Variable 2016  Other Long-term Debt 75
 Variable 2016
              
Non-Registrant:Non-Registrant:              
    
AEPTCo Senior Unsecured Notes 30
 5.42 2044
AGR Pollution Control Bonds 79
 Variable 2015
AGR Pollution Control Bonds 60
(a)Variable 2038
KPCo Pollution Control Bonds 65
(a)Variable 2036
TCC Senior Unsecured Notes 50
 2.61 2019
TCC Senior Unsecured Notes 50
 3.81 2026
TCC Senior Unsecured Notes 100
 4.67 2044
Transource MissouriTransource Missouri Other Long-term Debt   27   Variable 2018  Other Long-term Debt 39
 Variable 2018
Total IssuancesTotal Issuances   $ 77 (a)       $948
(b)   
          
   Principal  Interest  
Company Type of Debt Amount Paid  Rate Due Date
Retirements and  (in millions) (%)  
Principal Payments:          
I&M Notes Payable $5   Variable 2016 
I&M Notes Payable  4   2.12  2016 
I&M Notes Payable   5  Variable 2016 
I&M Notes Payable  10   Variable 2017 
I&M Other Long-term Debt  2   Variable 2015 
OPCo Senior Unsecured Notes  225   4.85  2014 
SWEPCo Notes Payable  2   4.58  2032 
           
Non-Registrant:          
AEGCo Senior Unsecured Notes  4   6.33  2037 
AEP Subsidiaries Notes Payable  1   Variable 2017 
TCC Securitization Bonds  72   5.09  2015 
TCC Securitization Bonds  40   6.25  2016 
Total Retirements and          
Principal Payments   $370      

(a)Pollution Control Bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year.
(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.issuance amount.

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Company Type of Debt 
Principal
Amount Paid
 Interest
Rate		 Due Date
Total Retirements and Principal Payments:   (in millions) (%)  
APCo Other Long-term Debt $300
 Variable 2015
APCo Senior Unsecured Notes 200
 4.95 2015
I&M Notes Payable 19
 Variable 2017
I&M Notes Payable 14
 Variable 2016
I&M Notes Payable 7
 2.12 2016
I&M Notes Payable 10
 Variable 2016
I&M Notes Payable 4
 4.00 2014
I&M Other Long-term Debt 5
 Variable 2015
I&M Other Long-term Debt 1
 6.00 2025
I&M Pollution Control Bonds 100
 6.25 2014
OPCo Pollution Control Bonds 79
 3.25 2014
OPCo Pollution Control Bonds 60
 3.875 2014
OPCo Senior Unsecured Notes 225
 4.85 2014
PSO Pollution Control Bonds 34
 5.25 2014
SWEPCo Notes Payable 2
 4.58 2032
         
Non-Registrant:    
    
AEGCo Senior Unsecured Notes 4
 6.33 2037
AEP Subsidiaries Notes Payable 1
 8.03 2026
AEP Subsidiaries Notes Payable 1
 7.59 2026
AEP Subsidiaries Notes Payable 1
 Variable 2017
TCC Securitization Bonds 72
 5.09 2015
TCC Securitization Bonds 40
 6.25 2016
TCC Securitization Bonds 26
 0.88 2017
Total Retirements and Principal Payments   $1,205
    

66
In AprilJuly 2014, I&M retired $13$9 million of Notes Payable related to DCC Fuel.

In July 2014, OPCo retired $35 million of Securitization Bonds.

In July 2014, SWEPCo issued a $100 million three-year term credit facility and drew the full amount.

In July 2014, TCC retired $112 million of Securitization Bonds.

As of March 31,June 30, 2014, trustees held on our behalf, $500$435 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 primarily 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

89


outstanding debt and capitalization is contractually defined in the credit agreements.  None of AEP’s retained earnings were restricted for the purpose of the payment of dividends.

Utility Subsidiaries’ Restrictions

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

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

Short-term Debt

Our outstanding short-term debt was as follows:

  March 31, 2014 December 31, 2013
  Outstanding Interest Outstanding Interest June 30, 2014 December 31, 2013
Type of DebtType of DebtAmountRate (a) AmountRate (a) 
Outstanding
Amount
 
Interest
Rate (a)
 Outstanding
Amount		 Interest
Rate (a)
 (in millions)    (in millions)    (in millions)  
 (in millions)  
Securitized Debt for Receivables (b)Securitized Debt for Receivables (b) $ 700   0.24 % $ 700   0.23 % $750
 0.23% $700
 0.23%
Commercial PaperCommercial Paper   632   0.31 %   57   0.29 % 732
 0.27% 57
 0.29%
Total Short-term DebtTotal Short-term Debt $ 1,332     $ 757     $1,482
  
 $757
  

(a)Weighted average rate.
(b)Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance.

Credit Facilities

For an additional discussion of credit facilities, see “Letters of Credit” section of Note 5.

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.

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Our receivables securitization agreement provides a commitment of $700$750 million from bank conduits to purchase receivables. A commitment of $385The agreement was increased in June 2014 from $700 million and expires in June 2014.  The remaining commitment of $315 million expires in June 2015.  We intend to extend or replace the agreement expiring in June 2014 on or before its maturity.2016.


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Accounts receivable information for AEP Credit is as follows:

   Three Months Ended 
   March 31, 
   2014  2013  
  (dollars in millions) 
Effective Interest Rates on Securitization of Accounts Receivable   0.24 %  0.23 %
Net Uncollectible Accounts Receivable Written Off $ 8  $ 7  
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 2014 2013 2014 2013
 (dollars in millions)
Effective Interest Rates on Securitization of 
  
  
  
Accounts Receivable0.22% 0.22% 0.23% 0.23%
Net Uncollectible Accounts Receivable 
  
  
  
Written Off$7
 $7
 $14
 $14

   March 31, December 31,
   2014  2013 
   (in millions)
Accounts Receivable Retained Interest and Pledged as Collateral      
 Less Uncollectible Accounts $ 997  $ 929 
Total Principal Outstanding   700    700 
Delinquent Securitized Accounts Receivable   55    45 
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable   17    16 
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable   278    331 
 
June 30,
2014
 
December 31,
2013
 (in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
Less Uncollectible Accounts
$1,040
 $929
Total Principal Outstanding750
 700
Delinquent Securitized Accounts Receivable56
 45
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable19
 16
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable383
 331

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.


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12.  13.  VARIABLE INTEREST ENTITIES

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

We are the primary beneficiary of Sabine, DCC Fuel, AEP Credit, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, a protected cell of EIS and Transource Energy.  In addition, we have not provided material financial or other support to Sabine, DCC Fuel, AEP Credit, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, our protected cell of EIS and Transource Energy 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 March 31,June 30, 2014 and 2013 were $39$41 million and $44$40 million, respectively, and for the six months ended June 30, 2014 and 2013 were $80 million and $84 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on the condensed balance sheets.

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I&M has nuclear fuel lease agreements with DCC Fuel II 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 March 31,June 30, 2014 and 2013 were $25$32 million and $26$38 million, respectively, and for the six months ended June 30, 2014 and 2013 were $56 million and $64 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months.  Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  In October 2013, the lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC.  See the tables below for the classification of DCC Fuel’s assets and liabilities on the condensed balance sheets.

AEP Credit is a wholly-owned subsidiary of AEP.  AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements.  AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings.  Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing.  Based on our control of AEP Credit, management concluded that we are the primary beneficiary and are required to consolidate AEP Credit.  See the tables below for the classification of AEP Credit’s assets and liabilities on the condensed balance sheets.  See “Securitized Accounts ReceivablesReceivable – AEP Credit” section of Note 11.12.


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Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.  Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant.  Therefore, TCC is required to consolidate Transition Funding.  The securitized bonds totaled $2$1.9 billion and $2 billion as of March 31,June 30, 2014 and December 31, 2013, respectively.  Transition Funding has securitized transition assets of $1.8 billion and $1.9 billion as of March 31,June 30, 2014 and December 31, 2013, respectively.  The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT.  The securitization bonds are payable only from and secured by the securitized transition assets.  The bondholders have no recourse to TCC or any other AEP entity.  TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs.  See the tables below for the classification of Transition Funding’s assets and liabilities on the condensed balance sheets.

Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Phase-inphase-in recovery property.  Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant.  Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding.  The securitized bonds totaled $267 million and $267 million as of March 31,June 30, 2014 and December 31, 2013, respectively.  Ohio Phase-in-Recovery Funding has securitized assets of $127$122 million and $132 million as of March 31,June 30, 2014 and December 31, 2013, respectively.  The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO.  In August 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to OPCo or any other AEP entity.  OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs.  See the table below for the classification of Ohio Phase-in-Recovery Funding's assets and liabilities on the condensed balance sheets.

Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance.  Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant.  Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding.  The securitized bonds totaled $380 million and
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$380 $380 million as of March 31,June 30, 2014 and December 31, 2013, respectively.  Appalachian Consumer Rate Relief Funding has securitized assets of $365$361 million and $369 million as of March 31,June 30, 2014 and December 31, 2013, respectively.  The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC.  In November 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to APCo or any other AEP entity.  APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs.  See the tabletables below for the classification of Appalachian Consumer Rate Relief Funding's assets and liabilities on the condensed balance sheets.

The securitized bonds of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in current and long-term debt on the condensed balance sheets. The securitized assets of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in securitized assets 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

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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 EIS.  Our insurance premium expense to the protected cell for the three months ended March 31,June 30, 2014 and 2013 was $16were $1.4 million and $14 thousand, respectively, and for the six months ended June 30, 2014 and 2013 were $18 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.

Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity. AEP's equity interest could potentially be significant.  Therefore, AEP is required to consolidate Transource Energy. AEP’s equity interest could potentially be significant. In January 2014, Transource Missouri acquired transmission assets from the non-controlling owner and issued debt and received a capital contributionscontribution to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, debt issuance and capital contribution. See the tabletables below for the classification of Transource Energy’s assets and liabilities on the condensed balance sheets.

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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
March 31, 2014
(in millions)
                          
                 APCo      
               OPCo Appalachian      
               Ohio Consumer      
            TCC Phase-in- Rate Protected   
   SWEPCo I&M AEP Transition Recovery Relief Cell Transource
   SabineDCC FuelCreditFunding Funding Funding of EIS Energy
ASSETS                        
Current Assets $ 62  $ 109  $ 1,004  $ 166  $ 36  $ 16  $ 152  $4 
Net Property, Plant and                        
 Equipment   154    129    -    -    -    -    -   57 
Other Noncurrent Assets   50    45    -    1,861 (a)  242 (b)  374 (c)  3   5 
Total Assets $ 266  $ 283  $ 1,004  $ 2,027  $ 278  $ 390  $ 155  $ 66 
                          
LIABILITIES AND EQUITY                        
Current Liabilities $ 29  $ 100  $ 894  $ 304  $ 60  $ 28  $ 48  $18 
Noncurrent Liabilities   236    183    1    1,705    217    360    67   28 
Equity   1    -    109    18    1    2    40   20 
Total Liabilities and Equity $ 266  $ 283  $ 1,004  $ 2,027  $ 278  $ 390  $ 155  $ 66 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
June 30, 2014
(in millions)
  
SWEPCo
Sabine
 
I&M
DCC Fuel
 
AEP
Credit
 
TCC
Transition
Funding
 
OPCo
Ohio
Phase-in-
Recovery
Funding
  
APCo
Appalachian
Consumer
Rate Relief
Funding
 
Protected
Cell
of EIS
 
Transource
Energy
ASSETS    
  
         
  
Current Assets $59
 $88
 $1,048
 $218
 $48
  $23
 $152
 $3
Net Property, Plant and                 
Equipment 153
 97
 —
 —
 —
  —
 —
 73
Other Noncurrent Assets 51
 35
 1
 1,805
(a) 232
(b)  369
(c)3
 4
Total Assets $263
 $220
 $1,049
 $2,023
 $280
  $392
 $155
 $80
                  
LIABILITIES AND EQUITY  
  
  
  
  
     
  
Current Liabilities $29
 $84
 $948
 $320
 $61
  $30
 $41
 $14
Noncurrent Liabilities 234
 136
 —
 1,685
 218
  360
 73
 39
Equity —
 —
 101
 18
 1
  2
 41
 27
Total Liabilities and Equity $263
 $220
 $1,049
 $2,023
 $280
  $392
 $155
 $80

(a)Includes an intercompany item eliminated in consolidation of $81$79 million.
(b)Includes an intercompany item eliminated in consolidation of $112 million.
(c)Includes an intercompany item eliminated in consolidation of $4 million.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2013
(in millions)
                      
                 APCo   
              OPCo Appalachian   
              Ohio Consumer   
           TCC Phase-in- Rate   
  SWEPCo I&M AEP Transition Recovery Relief Protected Cell
  SabineDCC FuelCreditFunding Funding Funding of EIS
ASSETS                     
Current Assets $ 67  $ 118  $ 935  $ 232  $ 23  $ 6  $ 143 
Net Property, Plant and Equipment   157    157    -    -    -    -    - 
Other Noncurrent Assets   51    60    1    1,918 (a)  252 (b)  378 (c)   3 
Total Assets $ 275  $ 335  $ 936  $ 2,150  $ 275  $ 384  $ 146 
                      
LIABILITIES AND EQUITY                     
Current Liabilities $ 33  $ 108  $ 827  $ 312  $ 37  $ 14  $ 39 
Noncurrent Liabilities   242    227    1    1,820    237    368    66 
Equity   -    -    108    18    1    2    41 
Total Liabilities and Equity $ 275  $ 335  $ 936  $ 2,150  $ 275  $ 384  $ 146 
(a)Includes an intercompany item eliminated in consolidation of $82 million.
(b)Includes an intercompany item eliminated in consolidation of $116$108 million.
(c)Includes an intercompany item eliminated in consolidation of $4 million.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2013
(in millions)
71
  
SWEPCo
Sabine
 
I&M
DCC
Fuel
 
AEP
Credit
 
TCC
Transition
Funding
  
OPCo
Ohio
Phase-in-
Recovery
Funding
  
APCo
Appalachian
Consumer
Rate Relief
Funding
  
Protected
Cell
of EIS
ASSETS    
  
           
Current Assets $67
 $118
 $935
 $232
  $23
  $6
  $143
Net Property, Plant and Equipment 157
 157
 —
 —
  —
  —
  —
Other Noncurrent Assets 51
 60
 1
 1,918
(a)  252
(b) 378
(c) 3
Total Assets $275
 $335
 $936
 $2,150
  $275
  $384
  $146
                  
LIABILITIES AND EQUITY  
  
  
  
   
   
   
Current Liabilities $33
 $108
 $827
 $312
  $37
  $14
  $39
Noncurrent Liabilities 242
 227
 1
 1,820
  237
  368
  66
Equity —
 —
 108
 18
  1
  2
  41
Total Liabilities and Equity $275
 $335
 $936
 $2,150
  $275
  $384
  $146

(a)
Includes an intercompany item eliminated in consolidation of $82 million.
(b)Includes an intercompany item eliminated in consolidation of $116 million.
(c)Includes an intercompany item eliminated in consolidation of $4 million.

DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and voting rights equally.  Each entity guarantees 50% of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  SWEPCo’s total billings from DHLC for the three months ended March 31,June 30, 2014 and 2013 were $2$6 million and $18$13 million, respectively, and for the six months ended June 30, 2014 and 2013 were $8 million and $31 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:

 March 31, 2014 December 31, 2013
 As Reported on Maximum As Reported on MaximumJune 30, 2014 December 31, 2013
 the Balance SheetExposure the Balance Sheet Exposure
As Reported on
the Balance Sheet
 
Maximum
Exposure
 
As Reported on
the Balance Sheet
 
Maximum
Exposure
 (in millions)(in millions)
Capital Contribution from SWEPCo $ 8  $ 8  $ 8  $ 8 $8
 $8
 $8
 $8
Retained Earnings   2   2    1    1 2
 2
 1
 1
SWEPCo's Guarantee of Debt   -    85    -    61 —
 116
 —
 61
                  
Total Investment in DHLC $ 10  $ 95  $ 9  $ 70 $10
 $126
 $9
 $70

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.

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In August 2012, the PJM board cancelled the PATH Project, ourthe transmission joint venture with FirstEnergy,project that PATH was intended to develop, and removed it from the 2012 Regional Transmission Expansion Plan.  In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project’sProject's abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case have been unable to reach a settlement agreement.  Inagreement and in March 2014, the settlement judge recommended termination ofprocedures were terminated. A hearing at the settlement proceedings and this caseFERC is expected to proceed to a hearing.scheduled for January 2015.

Our investment in PATH-WV was:

March 31, 2014 December 31, 2013
As Reported on Maximum As Reported on MaximumJune 30, 2014 December 31, 2013
the Balance SheetExposurethe Balance SheetExposure
As Reported on
the Balance Sheet
 
Maximum
Exposure
 
As Reported on
the Balance Sheet
 
Maximum
Exposure
  (in millions)  (in millions)
Capital Contribution from AEP$ 19  $ 19  $ 19  $ 19 $19
 $19
 $19
 $19
Retained Earnings  6    6    6    6 6
 6
 6
 6
               
Total Investment in PATH-WV$ 25  $ 25  $ 25  $ 25 $25
 $25
 $25
 $25

As of March 31,June 30, 2014, our $25 million investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheet. If we cannot ultimately recover our investment related to PATH-WV, it could reduce future net income and cash flows.



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72


APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

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73



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

EXECUTIVE OVERVIEW

Regulatory Activity

Plant Transfer

In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo. Management anticipates an order related to the proposed plant transfer will be issued in the fourth quarter of 2014. In April 2014, APCo and WPCo also filed a request with the FERC for approval to transfer AGR’s one-half interest in the Mitchell Plant to WPCo. In June 2014, the FERC issued an order approving this request. Also in June 2014, an intervenor filed a motion to stay the proceeding at the WVPSC until alternatives to the acquisition of the Mitchell Plant have been explored. In accordance with a July 2014 order addressing the motion to stay, APCo filed supplemental testimony to address intervenor concerns. In July 2014, the WVPSC issued an order that modified the procedural schedule. A hearing at the WVPSC is scheduled for September 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Upon transfer of the Mitchell Plant to WPCo, WPCo will no longer purchase power from AGR. See the “Plant Transfer” section of APCo Rate Matters in Note 4.

WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting authority to merge WPCo into APCo. In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC. In April 2013, the FERC approved the merger. Also in December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval 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. In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo. In December 2013, the WVPSC issued an order that deferred ruling on the merger of WPCo into APCo. The feasibility of the merger remains under review. See the “WPCo Merger with APCo” section of APCo Rate Matters in Note 4.4.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a biennial generation and distribution base rate biennial reviewcase with the Virginia SCC. In accordance with a Virginia statute, APCo did not request an increase in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to the change in the expected service life of certain plants. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to certainIGCC and other deferred costs. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 Virginia Biennial Base Rate Case” section of APCo Rate Matters in Note 4.4.

2014 West Virginia Base Rate Case

In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $156 million, based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates and requested amortization of $77 million over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $38 million annually to recover total vegetation management costs. If any of these

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costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 West Virginia Base Rate Case” section of APCo Rate Matters in Note 4.

Litigation and Environmental Issues

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 –- Rate Matters and Note 5 –- Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 – - Rate Matters and Note 5 – - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 132.164. 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 186243 for additional discussion of relevant factors.

74
RESULTS OF OPERATIONS

KWh Sales/Degree Days

       
Summary of KWh Energy Sales
 
  Three Months Ended March 31,
 2014  2013 
  (in millions of KWhs)
Retail:     
 Residential  4,362    4,001 
 Commercial  1,780    1,742 
 Industrial  2,492    2,588 
 Miscellaneous  222    217 
Total Retail  8,856    8,548 
      
Wholesale  1,071    2,281 
      
Total KWhs  9,927    10,829 
Summary of KWh Energy Sales
 Three Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in millions of KWhs)
Retail: 
  
  
  
Residential2,266
 2,256
 6,628
 6,257
Commercial1,644
 1,617
 3,424
 3,359
Industrial2,573
 2,655
 5,065
 5,243
Miscellaneous209
 198
 431
 415
Total Retail6,692
 6,726
 15,548
 15,274
        
Wholesale873
 1,788
 1,944
 4,069
        
Total KWhs7,565
 8,514
 17,492
 19,343

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

Summary of Heating and Cooling Degree Days
 
  Three Months Ended March 31,
 2014  2013 
  (in degree days)
       
Actual - Heating (a)  1,715    1,404 
Normal - Heating (b)  1,311    1,312 
       
Actual - Cooling (c)  -    - 
Normal - Cooling (b)  7    7 
       
(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.
Summary of Heating and Cooling Degree Days
 Three Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in degree days)
Actual - Heating (a)61
 92
 1,776
 1,497
Normal - Heating (b)92
 93
 1,403
 1,405
        
Actual - Cooling (c)402
 388
 402
 388
Normal - Cooling (b)360
 360
 367
 367

(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.

99
75


First
Second Quarter of 2014 Compared to FirstSecond Quarter of 2013

Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income
(in millions)
First Quarter of 2013$ 71 
Changes in Gross Margin:
Retail Margins 35 
Off-system Sales 1 
Transmission Revenues 4 
Other Revenues 11 
Total Change in Gross Margin 51 
Changes in Expenses and Other:
Other Operation and Maintenance 25 
Depreciation and Amortization (17)
Taxes Other Than Income Taxes (4)
Carrying Costs Income (2)
Other Income 1 
Interest Expense (4)
Total Change in Expenses and Other (1)
Income Tax Expense (19)
First Quarter of 2014$ 102 
Reconciliation of Second Quarter of 2013 to Second Quarter of 2014
Net Income
(in millions)
 
Second Quarter of 2013 $30
   
Changes in Gross Margin:  
Retail Margins 70
Off-system Sales (2)
Transmission Revenues (2)
Other Revenues (2)
Total Change in Gross Margin 64
   
Changes in Expenses and Other:  
Other Operation and Maintenance (31)
Depreciation and Amortization (12)
Taxes Other Than Income Taxes (2)
Carrying Costs Income (3)
Other Income (1)
Interest Expense (5)
Total Change in Expenses and Other (54)
   
Income Tax Expense (4)
   
Second Quarter of 2014 $36

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 $70 million primarily due to the following:
A $46 million increase primarily due to increases in rates in Virginia and West Virginia.  Of these increases, $25 million relate to riders/trackers which have corresponding increases in other expense items below.
Retail Margins increased $35 million primarily due to the following:
·A $27 million increase primarily due to a 22% increase in heating degree days.
·A $26 million increase primarily due to changes in rates in West Virginia.  Of these increases, $10 million relate to riders/trackers which have corresponding increases in other expense items below.
·A $19 million decrease in capacity settlement expenses due to the termination of the Interconnection Agreement.
·A $6 million decrease in other variable electric generation expenses.
These increases were partially offset by:
·A $13 million increase in PJM expenses.
·A $10 million decrease due to increased sales of renewable energy credits in 2014.  This decrease is offset in Other Revenues.
·A $7 million increase in expense due to the timing of fuel recovery.
·A $4 million decrease primarily due to lower industrial usage.
·
Transmission Revenues increased $4 million primarily due to increased investments in the PJM region.  These increased revenues are offset in Other Operation and Maintenance expenses below.
·
Other Revenues increased $11 million primarily due to increased sales of renewable energy credits.  This increase in revenues is mainly offset in Retail Margins in fuel recovery.

76
Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses increased $31 million primarily due to the following:
A $15 million increase in transmission expenses primarily due to PJM services.
A $9 million increase in steam maintenance expenses at Amos Plant partially driven by APCo's increased ownership of the plant.
Depreciation and Amortization expenses increased $12 million primarily due to an increase in depreciable base including the increased ownership in Amos Plant.
Interest Expense increased $5 million primarily due to the November 2013 issuance of securitization bonds and the assumption of debt related to increased ownership of Amos Plant in December 2013.
Income Tax ExpenseOther Operation and Maintenance expenses decreased $25 million primarily due to the following:
·A $30 million write-off in the first quarter of 2013 of previously deferred Virginia storm costs resulting from the 2013 enactment of a Virginia law.
·A $15 million decrease in distribution maintenance expense primarily due to the January 2013 snow storm.
These decreases were partially offset by:
·A $6 million increase in transmission expenses due to increased investment in the PJM region.  These expenses are partially offset in Transmission Revenues.
·A $5 million increase in steam operation and maintenance expenses.
·A $2 million increase in employee-related expenses.
·
Depreciation and Amortization expenses increased $17 million primarily due to:
·An $11 million increase primarily due to higher depreciable base.
·A $3 million increase due to over-recovery of revenues for securitization.
·
Taxes Other Than Income Taxes expenses increased $4 million primarily due to:
·A $2 million increase in state business occupation tax and state minimum tax accruals.
·A $1 million increase in real and personal property taxes amortization.
·
Interest Expense increased $4 million primarily due to the issuance of securitization bonds and the assumption of debt related to corporate separation.
·
Income Tax Expense increased $19 million primarily due to an increase in pretax book income.


100


Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Reconciliation of Six Months Ended June 30, 2013 to Six Months Ended June 30, 2014
Net Income
(in millions)
 
Six Months Ended June 30, 2013 $100
   
Changes in Gross Margin:  
Retail Margins 116
Off-system Sales (1)
Transmission Revenues 1
Other Revenues (1)
Total Change in Gross Margin 115
   
Changes in Expenses and Other:  
Other Operation and Maintenance (6)
Depreciation and Amortization (29)
Taxes Other Than Income Taxes (5)
Carrying Costs Income (5)
Interest Expense (9)
Total Change in Expenses and Other (54)
   
Income Tax Expense (23)
   
Six Months Ended June 30, 2014 $138

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

Retail Margins increased $116 million primarily due to the following:
A $72 million increase primarily due to increases in rates in West Virginia and Virginia.  Of these increases, $40 million relate to riders/trackers which have corresponding increases in other expense items below.
A $38 million decrease in capacity settlement expenses due to the termination of the Interconnection Agreement.
A $26 million increase in weather-related usage primarily due to a 19% increase in heating degree days.
A $10 million decrease in other variable electric generation expenses.
These increases were partially offset by:
A $13 million increase in PJM expenses.

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 $25 million increase in steam operation and maintenance expenses primarily associated with activities at Amos Plant partially driven by APCo's increased ownership of the plant.
A $15 million increase in transmission expenses primarily due to PJM services.
A $9 million increase in transmission expenses due to increased investment in the PJM region. These expenses are primarily offset in Transmission Revenues.
These increases were partially offset by:
A $30 million write-off in the first quarter of 2013 of previously deferred Virginia storm costs resulting from the 2013 enactment of a Virginia law.

101


A $20 million decrease in distribution maintenance expense due to $25 million of storm expenses in January and June 2013 partially offset by $5 million of storm expenses in June 2014.
Depreciation and Amortization expenses increased $29 million primarily due to the following:
A $21 million increase due to an increase in depreciable base including the increased ownership in Amos Plant.
A $5 million increase due to amortization of Virginia Environmental deferrals. This increase in expense is offset within Retail Margins above.
Taxes Other Than Income Taxes increased $5 million due to:
A $3 million increase in real and personal property taxes amortization.
A $2 million increase in state business occupation tax and state minimum tax expense.
Carrying Costs Income decreased $5 million primarily due to the November 2013 securitization of the West Virginia ENEC deferral balance.
Interest Expense increased $9 million primarily due to the November 2013 issuance of securitization bonds and the assumption of debt related to APCo's increased ownership of Amos Plant in December 2013.
Income Tax Expense increased $23 million primarily due to an increase in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2013 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 186243 for a discussion of accounting pronouncements.

77

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
        
   Three Months Ended March 31,
   2014  2013 
REVENUES     
Electric Generation, Transmission and Distribution $ 866,457  $ 872,732 
Sales to AEP Affiliates   44,914    76,860 
Other Revenues   2,020    1,902 
TOTAL REVENUES   913,391    951,494 
       
EXPENSES      
Fuel and Other Consumables Used for Electric Generation   230,737    204,939 
Purchased Electricity for Resale   168,991    65,456 
Purchased Electricity from AEP Affiliates   4,662    222,942 
Other Operation   93,538    78,908 
Maintenance   60,090    99,386 
Depreciation and Amortization   104,586    87,903 
Taxes Other Than Income Taxes   30,777    27,400 
TOTAL EXPENSES   693,381    786,934 
       
OPERATING INCOME   220,010    164,560 
       
Other Income (Expense):      
Interest Income   401    331 
Carrying Costs Income (Expense)   (1,875)   103 
Allowance for Equity Funds Used During Construction   1,235    770 
Interest Expense   (51,672)   (48,204)
       
INCOME BEFORE INCOME TAX EXPENSE   168,099    117,560 
       
Income Tax Expense   66,248    47,012 
       
NET INCOME $ 101,851  $ 70,548 
 
The common stock of APCo is wholly-owned by AEP.
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

102
78
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
        
   Three Months Ended March 31,
   2014  2013 
Net Income $101,851  $70,548 
        
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES      
Cash Flow Hedges, Net of Tax of $132 and $677 in 2014 and 2013, Respectively   246   1,258 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $179 and $193      
 in 2014 and 2013, Respectively  (333)   358 
        
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)  (87)  1,616 
        
TOTAL COMPREHENSIVE INCOME $101,764  $72,164 
        
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.      

79


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
                   
              Accumulated  
              Other  
     Common Paid-in Retained Comprehensive  
     Stock Capital Earnings Income (Loss) Total
TOTAL COMMON SHAREHOLDER'S               
 EQUITY – DECEMBER 31, 2012 $ 260,458  $ 1,573,752  $ 1,248,250  $ (29,898) $ 3,052,562 
                   
Common Stock Dividends         (50,000)      (50,000)
Net Income         70,548       70,548 
Other Comprehensive Income            1,616    1,616 
TOTAL COMMON SHAREHOLDER'S               
 EQUITY – MARCH 31, 2013 $ 260,458  $ 1,573,752  $ 1,268,798  $ (28,282) $ 3,074,726 
                   
TOTAL COMMON SHAREHOLDER'S               
 EQUITY – DECEMBER 31, 2013 $ 260,458  $ 1,809,562  $ 1,156,461  $ 2,951  $ 3,229,432 
                   
Common Stock Dividends         (20,000)      (20,000)
Net Income         101,851       101,851 
Other Comprehensive Loss            (87)   (87)
TOTAL COMMON SHAREHOLDER'S               
 EQUITY – MARCH 31, 2014 $ 260,458  $ 1,809,562  $ 1,238,312  $ 2,864  $ 3,311,196 
                   
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.   
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
  Three Months Ended Six Months Ended
  June 30, June 30,
  2014 2013 2014 2013
REVENUES        
Electric Generation, Transmission and Distribution $664,051
 $670,249
 $1,530,508
 $1,542,981
Sales to AEP Affiliates 28,070
 73,893
 72,984
 150,753
Other Revenues 2,547
 2,362
 4,567
 4,264
TOTAL REVENUES 694,668
 746,504
 1,608,059
 1,697,998
         
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 202,903
 163,521
 433,640
 368,460
Purchased Electricity for Resale 86,033
 59,487
 255,024
 124,943
Purchased Electricity from AEP Affiliates —
 181,856
 4,662
 404,798
Other Operation 99,896
 79,764
 193,434
 158,672
Maintenance 69,484
 58,560
 129,574
 157,946
Depreciation and Amortization 95,650
 83,240
 200,236
 171,143
Taxes Other Than Income Taxes 30,025
 28,004
 60,802
 55,404
TOTAL EXPENSES 583,991
 654,432
 1,277,372
 1,441,366
         
OPERATING INCOME 110,677
 92,072
 330,687
 256,632
         
Other Income (Expense):  
  
  
  
Interest Income 389
 1,469
 790
 1,800
Carrying Costs Income (Expense) 263
 3,133
 (1,612) 3,236
Allowance for Equity Funds Used During Construction 1,625
 1,213
 2,860
 1,983
Interest Expense (53,130) (48,128) (104,802) (96,332)
         
INCOME BEFORE INCOME TAX EXPENSE 59,824
 49,759
 227,923
 167,319
         
Income Tax Expense 23,577
 19,897
 89,825
 66,909
         
NET INCOME $36,247
 $29,862
 $138,098
 $100,410
The common stock of APCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.



103


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
80
  
  Three Months Ended
 Six Months Ended
  June 30, June 30,
  2014 2013 2014 2013
Net Income $36,247
 $29,862
 $138,098
 $100,410
         
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
  
  
  
Cash Flow Hedges, Net of Tax of $90 and $48 for the Three Months Ended June 30, 2014 and 2013, Respectively, and $222 and $725 for the Six Months Ended June 30, 2014 and 2013, Respectively 166
 89
 412
 1,347
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $180 and $193 for the Three Months Ended June 30, 2014 and 2013, Respectively, and $359 and $386 for the Six Months Ended June 30, 2014 and 2013, Respectively (333) 358
 (666) 716
         
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) (167) 447
 (254) 2,063
         
TOTAL COMPREHENSIVE INCOME $36,080
 $30,309
 $137,844
 $102,473
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.



104


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
  
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 Total
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
           
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2013 $260,458
 $1,809,562
 $1,156,461
 $2,951
 $3,229,432
           
Common Stock Dividends  
  
 (40,000)  
 (40,000)
Net Income  
  
 138,098
  
 138,098
Other Comprehensive Loss  
  
  
 (254) (254)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2014 $260,458
 $1,809,562
 $1,254,559
 $2,697
 $3,327,276
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.




105


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2014 and December 31, 2013
(in thousands)
(Unaudited)
  June 30, December 31,
  2014 2013
CURRENT ASSETS    
Cash and Cash Equivalents $3,213
 $2,745
Advances to Affiliates 28,794
 92,485
Accounts Receivable:    
Customers 125,999
 142,010
Affiliated Companies 52,876
 113,793
Accrued Unbilled Revenues 37,911
 55,930
Miscellaneous 608
 412
Allowance for Uncollectible Accounts (2,742) (2,443)
Total Accounts Receivable 214,652
 309,702
Fuel 119,973
 191,811
Materials and Supplies 131,561
 128,843
Risk Management Assets 24,819
 21,171
Regulatory Asset for Under-Recovered Fuel Costs 76,364
 39,811
Prepayments and Other Current Assets 37,111
 16,472
TOTAL CURRENT ASSETS 636,487
 803,040
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 6,805,605
 6,745,172
Transmission 2,186,855
 2,160,660
Distribution 3,192,082
 3,139,150
Other Property, Plant and Equipment 369,950
 357,517
Construction Work in Progress 222,129
 184,701
Total Property, Plant and Equipment 12,776,621
 12,587,200
Accumulated Depreciation and Amortization 3,739,411
 3,617,990
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 9,037,210
 8,969,210
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 1,006,282
 1,003,890
Securitized Assets 360,612
 369,355
Long-term Risk Management Assets 8,110
 16,948
Deferred Charges and Other Noncurrent Assets 146,418
 148,205
TOTAL OTHER NONCURRENT ASSETS 1,521,422
 1,538,398
     
TOTAL ASSETS $11,195,119
 $11,310,648
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.



106


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2014 and December 31, 2013
(Unaudited)
  June 30, December 31,
  2014 2013
  (in thousands)
CURRENT LIABILITIES    
Accounts Payable:  
  
General $171,159
 $169,184
Affiliated Companies 74,714
 120,789
Long-term Debt Due Within One Year – Nonaffiliated 653,400
 342,360
Long-term Debt Due Within One Year – Affiliated 86,000
 —
Risk Management Liabilities 4,226
 8,892
Customer Deposits 65,167
 66,040
Deferred Income Taxes 27,518
 6,899
Accrued Taxes 95,917
 114,699
Accrued Interest 54,906
 51,899
Regulatory Liability for Over-Recovered Fuel Costs 31,776
 107,048
Other Current Liabilities 84,470
 97,566
TOTAL CURRENT LIABILITIES 1,349,253
 1,085,376
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 3,253,217
 3,765,997
Long-term Debt – Affiliated —
 86,000
Long-term Risk Management Liabilities 3,766
 10,241
Deferred Income Taxes 2,315,231
 2,232,441
Regulatory Liabilities and Deferred Investment Tax Credits 668,971
 631,225
Employee Benefits and Pension Obligations 98,039
 82,264
Deferred Credits and Other Noncurrent Liabilities��179,366
 187,672
TOTAL NONCURRENT LIABILITIES 6,518,590
 6,995,840
     
TOTAL LIABILITIES 7,867,843
 8,081,216
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
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 1,809,562
 1,809,562
Retained Earnings 1,254,559
 1,156,461
Accumulated Other Comprehensive Income (Loss) 2,697
 2,951
TOTAL COMMON SHAREHOLDER’S EQUITY 3,327,276
 3,229,432
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $11,195,119
 $11,310,648
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.


107


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
  Six Months Ended June 30,
  2014 2013
OPERATING ACTIVITIES  
  
Net Income $138,098
 $100,410
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 200,236
 171,143
Deferred Income Taxes 90,236
 42,158
Carrying Costs Income 1,612
 (3,236)
Allowance for Equity Funds Used During Construction (2,860) (1,983)
Mark-to-Market of Risk Management Contracts (6,025) 6,765
Pension Contributions to Qualified Plan Trust (8,963) —
Fuel Over/Under-Recovery, Net (108,943) 25,919
Change in Other Noncurrent Assets 2,861
 35,219
Change in Other Noncurrent Liabilities 23,626
 9,670
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net 93,553
 73,280
Fuel, Materials and Supplies 69,120
 (36,078)
Accounts Payable (46,812) (57,034)
Accrued Taxes, Net (9,690) 18,058
Other Current Assets (2,294) 1,621
Other Current Liabilities (10,469) (14,440)
Net Cash Flows from Operating Activities 423,286
 371,472
     
INVESTING ACTIVITIES  
  
Construction Expenditures (224,879) (194,200)
Change in Advances to Affiliates, Net 63,691
 (279)
Other Investing Activities (14,754) (108)
Net Cash Flows Used for Investing Activities (175,942) (194,587)
     
FINANCING ACTIVITIES  
  
Issuance of Long-term Debt – Nonaffiliated 295,042
 —
Change in Advances from Affiliates, Net —
 (86,182)
Retirement of Long-term Debt – Nonaffiliated (500,016) (14)
Principal Payments for Capital Lease Obligations (2,904) (2,623)
Dividends Paid on Common Stock (40,000) (90,000)
Other Financing Activities 1,002
 1,093
Net Cash Flows Used for Financing Activities (246,876) (177,726)
     
Net Increase (Decrease) in Cash and Cash Equivalents 468
 (841)
Cash and Cash Equivalents at Beginning of Period 2,745
 3,576
Cash and Cash Equivalents at End of Period $3,213
 $2,735
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $96,564
 $92,994
Net Cash Paid for Income Taxes 1,280
 425
Noncash Acquisitions Under Capital Leases 3,133
 2,422
Construction Expenditures Included in Current Liabilities as of June 30, 50,052
 34,114
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.



108



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2014 and December 31, 2013
(in thousands)
(Unaudited)
 
    March 31, December 31,
  2014  2013 
CURRENT ASSETS      
Cash and Cash Equivalents $ 4,758  $ 2,745 
Advances to Affiliates   245,516    92,485 
Accounts Receivable:      
 Customers   150,954    142,010 
 Affiliated Companies   72,283    113,793 
 Accrued Unbilled Revenues   46,631    55,930 
 Miscellaneous   472    412 
 Allowance for Uncollectible Accounts   (3,517)   (2,443)
  Total Accounts Receivable   266,823    309,702 
Fuel   103,983    191,811 
Materials and Supplies   128,614    128,843 
Risk Management Assets   15,972    21,171 
Regulatory Asset for Under-Recovered Fuel Costs   79,498    39,811 
Prepayments and Other Current Assets   33,677    16,472 
TOTAL CURRENT ASSETS   878,841    803,040 
       
PROPERTY, PLANT AND EQUIPMENT      
Electric:      
 Generation   6,752,422    6,745,172 
 Transmission   2,173,839    2,160,660 
 Distribution   3,161,917    3,139,150 
Other Property, Plant and Equipment   365,750    357,517 
Construction Work in Progress   217,713    184,701 
Total Property, Plant and Equipment   12,671,641    12,587,200 
Accumulated Depreciation and Amortization   3,679,394    3,617,990 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
   8,992,247    8,969,210 
         
OTHER NONCURRENT ASSETS      
Regulatory Assets   1,006,426    1,003,890 
Securitized Assets   364,984    369,355 
Long-term Risk Management Assets   14,013    16,948 
Deferred Charges and Other Noncurrent Assets   157,592    148,205 
TOTAL OTHER NONCURRENT ASSETS   1,543,015    1,538,398 
       
TOTAL ASSETS $ 11,414,103  $ 11,310,648 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.
81
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
March 31, 2014 and December 31, 2013
(Unaudited)
 
    March 31, December 31,
  2014  2013 
   (in thousands)
CURRENT LIABILITIES      
Accounts Payable:      
 General $ 188,773  $ 169,184 
 Affiliated Companies   87,447    120,789 
Long-term Debt Due Within One Year – Nonaffiliated   553,399    342,360 
Risk Management Liabilities   4,636    8,892 
Customer Deposits   69,180    66,040 
Deferred Income Taxes   12,208    6,899 
Accrued Taxes   115,557    114,699 
Accrued Interest   62,397    51,899 
Regulatory Liability for Over-Recovered Fuel Costs   45,144    107,048 
Other Current Liabilities   76,445    97,566 
TOTAL CURRENT LIABILITIES   1,215,186    1,085,376 
       
NONCURRENT LIABILITIES      
Long-term Debt – Nonaffiliated   3,555,117    3,765,997 
Long-term Debt – Affiliated   86,000    86,000 
Long-term Risk Management Liabilities   7,929    10,241 
Deferred Income Taxes   2,297,662    2,232,441 
Regulatory Liabilities and Deferred Investment Tax Credits   648,895    631,225 
Employee Benefits and Pension Obligations   105,927    82,264 
Deferred Credits and Other Noncurrent Liabilities   186,191    187,672 
TOTAL NONCURRENT LIABILITIES   6,887,721    6,995,840 
       
TOTAL LIABILITIES   8,102,907    8,081,216 
       
Rate Matters (Note 4)      
Commitments and Contingencies (Note 5)      
       
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   1,809,562    1,809,562 
Retained Earnings   1,238,312    1,156,461 
Accumulated Other Comprehensive Income (Loss)   2,864    2,951 
TOTAL COMMON SHAREHOLDER’S EQUITY   3,311,196    3,229,432 
       
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $ 11,414,103  $ 11,310,648 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

82


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
 
     Three Months Ended March 31,
  2014  2013 
OPERATING ACTIVITIES      
Net Income $ 101,851  $ 70,548 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:      
  Depreciation and Amortization   104,586    87,903 
  Deferred Income Taxes   65,690    17,185 
  Carrying Costs Income   1,875    (103)
  Allowance for Equity Funds Used During Construction   (1,235)   (770)
  Mark-to-Market of Risk Management Contracts   1,625    9,404 
  Fuel Over/Under-Recovery, Net   (102,051)   20,135 
  Change in Other Noncurrent Assets   4,959    28,314 
  Change in Other Noncurrent Liabilities   7,799    5,634 
  Changes in Certain Components of Working Capital:      
   Accounts Receivable, Net   41,382    7,238 
   Fuel, Materials and Supplies   88,057    (8,726)
   Accounts Payable   (4,314)   (20,597)
   Accrued Taxes, Net   929    30,197 
   Other Current Assets   (7,276)   642 
   Other Current Liabilities   (6,707)   (10,917)
Net Cash Flows from Operating Activities   297,170    236,087 
       
INVESTING ACTIVITIES      
Construction Expenditures   (112,824)   (110,552)
Change in Advances to Affiliates, Net   (153,031)   (179)
Other Investing Activities   (8,677)   (179)
Net Cash Flows Used for Investing Activities   (274,532)   (110,910)
       
FINANCING ACTIVITIES      
Issuance of Long-term Debt – Nonaffiliated   (45)   (258)
Change in Advances from Affiliates, Net   -    (77,314)
Retirement of Long-term Debt – Nonaffiliated   (8)   (7)
Principal Payments for Capital Lease Obligations   (1,559)   (1,238)
Dividends Paid on Common Stock   (20,000)   (50,000)
Other Financing Activities   987    1,320 
Net Cash Flows Used for Financing Activities   (20,625)   (127,497)
       
Net Increase (Decrease) in Cash and Cash Equivalents   2,013    (2,320)
Cash and Cash Equivalents at Beginning of Period   2,745    3,576 
Cash and Cash Equivalents at End of Period $  4,758  $  1,256 
       
SUPPLEMENTARY INFORMATION      
Cash Paid for Interest, Net of Capitalized Amounts $  39,431  $ 31,018 
Net Cash Paid (Received) for Income Taxes   -    231 
Noncash Acquisitions Under Capital Leases   2,657    1,548 
Construction Expenditures Included in Current Liabilities as of March 31,   38,972    35,733 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

83

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
 
Page
Number
  
Significant Accounting Matters133
165
New Accounting PronouncementPronouncements133
166
Comprehensive Income134
167
Rate Matters141
186
Commitments, Guarantees and Contingencies149
196
Benefit Plans152
201
Business Segments153
204
Derivatives and Hedging154
205
Fair Value Measurements166
219
Income Taxes177
233
Financing Activities178
234
Variable Interest Entities181
238

109
84




INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES

110



85

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

EXECUTIVE OVERVIEW

Regulatory Activity

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 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 March 31,June 30, 2014, I&M has incurred costs of $405$439 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items which the IURC stated I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC. In May 2014, the IURC issued a final order approving the LCM rider rates that were implemented in January 2014.

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

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition. See “Cook Plant Life Cycle Management Project (LCM Project)” section of I&M Rate Matters in Note 4.4.

Litigation and Environmental Issues

In the ordinary course of business, I&M is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 –- Rate Matters and Note 5 –- Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 – - Rate Matters and Note 5 – - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 132.164. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission

111


control equipment and indemnify the plaintiff. The New York court granted the motion to transfer this case to the U.S. District Court for the Southern District of Ohio. AEGCo’s and I&M’s motion to dismiss the case, filed in October 2013, remains pending. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 186243 for additional discussion of relevant factors.

86
RESULTS OF OPERATIONS

KWh Sales/Degree Days

       
Summary of KWh Energy Sales
 
  Three Months Ended March 31,
 2014  2013 
  (in millions of KWhs)
Retail:     
 Residential  1,905    1,726 
 Commercial  1,221    1,188 
 Industrial  1,805    1,813 
 Miscellaneous  20    20 
Total Retail  4,951    4,747 
      
Wholesale  5,296    2,580 
      
Total KWhs  10,247    7,327 
Summary of KWh Energy Sales
 Three Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in millions of KWhs)
Retail: 
  
  
  
Residential1,161
 1,152
 3,066
 2,878
Commercial1,196
 1,197
 2,417
 2,385
Industrial1,963
 1,884
 3,768
 3,697
Miscellaneous15
 15
 35
 35
Total Retail4,335
 4,248
 9,286
 8,995
        
Wholesale3,870
 2,251
 9,166
 4,831
        
Total KWhs8,205
 6,499
 18,452
 13,826

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

Summary of Heating and Cooling Degree Days
 
  Three Months Ended March 31,
 2014  2013 
  (in degree days)
       
Actual - Heating (a)  2,972    2,287 
Normal - Heating (b)  2,149    2,155 
       
Actual - Cooling (c)  -    - 
Normal - Cooling (b)  2    2 
       
(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.
Summary of Heating and Cooling Degree Days
 Three Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in degree days)
Actual - Heating (a)244
 263
 3,216
 2,551
Normal - Heating (b)228
 230
 2,377
 2,385
        
Actual - Cooling (c)302
 278
 302
 278
Normal - Cooling (b)260
 260
 262
 262

(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.


112
87


FirstSecond Quarter of 2014 Compared to FirstSecond Quarter of 2013

Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income
(in millions)
First Quarter of 2013$ 43 
Changes in Gross Margin:
Retail Margins 27 
FERC Municipals and Cooperatives 10 
Off-system Sales 47 
Transmission Revenues 2 
Other Revenues (14)
Total Change in Gross Margin 72 
Changes in Expenses and Other:
Other Operation and Maintenance 1 
Depreciation and Amortization (9)
Taxes Other Than Income Taxes 1 
Other Income (3)
Interest Expense (1)
Total Change in Expenses and Other (11)
Income Tax Expense (17)
First Quarter of 2014$ 87 
Reconciliation of Second Quarter of 2013 to Second Quarter of 2014
Net Income
(in millions)
   
Second Quarter of 2013 $41
   
Changes in Gross Margin:  
Retail Margins (5)
FERC Municipals and Cooperatives (9)
Off-system Sales 9
Transmission Revenues 7
Other Revenues (2)
Total Change in Gross Margin —
   
Changes in Expenses and Other:  
Other Operation and Maintenance (18)
Depreciation and Amortization (4)
Taxes Other Than Income Taxes 1
Total Change in Expenses and Other (21)
   
Income Tax Expense 7
   
Second Quarter of 2014 $27

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

Retail Margins decreased $5 million primarily due to the following:
A $7 million decrease due to lower Indiana recovery of energy efficiency program costs. The decrease in revenue was partially offset by a corresponding decrease in energy efficiency expense items discussed below.
A $4 million decrease due to increased costs for power acquired under a unit power agreement.
These decreases were partially offset by:
A $6 million increase due to rate recovery under the Cook Plant Life Cycle Management Project rider effective January 2014.
Margins from FERC Municipal and Cooperatives decreased $9 million primarily due to the annual true-up adjustment of formula rates to actual costs.
Margins from Off-system Sales increased $9 million due to higher market prices and increased sales volumes.
Transmission Revenues increased $7 million primarily due to increased investment in the PJM region.

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

Other Operation and Maintenance expenses increased $18 million primarily due to the following:
A $10 million increase in transmission expenses primarily due to increased PJM expenses.
A $7 million increase in administrative and general expenses.
A $4 million increase in nuclear expenses.
These increases were partially offset by:
A $5 million decrease in customer services expense related to energy efficiency. The decrease in expenses was offset by a corresponding decrease in Retail Margins discussed above.
Depreciation and Amortization expenses increased $4 million primarily due to higher depreciable base.
Income Tax Expense decreased $7 million primarily due to a decrease in pretax book income.

113



Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Reconciliation of Six Months Ended June 30, 2013 to Six Months Ended June 30, 2014
Net Income
(in millions)
   
Six Months Ended June 30, 2013 $84
   
Changes in Gross Margin:  
Retail Margins 22
FERC Municipals and Cooperatives 1
Off-system Sales 56
Transmission Revenues 9
Other Revenues (16)
Total Change in Gross Margin 72
   
Changes in Expenses and Other:  
Other Operation and Maintenance (17)
Depreciation and Amortization (13)
Taxes Other Than Income Taxes 2
Other Income (3)
Interest Expense (1)
Total Change in Expenses and Other (32)
   
Income Tax Expense (10)
   
Six Months Ended June 30, 2014 $114

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 $27
Retail Margins increased $22 million primarily due to the following:
·A $22 million increase primarily due to a rate increase in Indiana effective March 2013.
·A $13 million increase in weather-related usage primarily due to a 30% increase in heating degree days.
These increases were partially offset by:
·An $8 million decrease for industrial customers primarily due to lower margins.
·
Margins from FERC Municipal and Cooperatives increased $10 million primarily due to higher formula rates effective June 2013.
·
Margins from Off-system Sales increased $47 million primarily due to higher market prices and increased sales volumes.
·
Other Revenues decreased $14 million primarily due to a decrease in barging.  This decrease in barging is a result of the River Transportation Division (RTD) no longer serving Ohio plants transferred to AGR as a result of corporate separation.  The decrease in RTD revenue was offset by a corresponding decrease in Other Operation and Maintenance expenses for barging as discussed below.
A $15 million increase in weather related usage primarily due to a 26% increase in heating degree days.
A $14 million increase due to a rate increase in Indiana effective March 2013.
A $13 million increase due to rate recovery under the Cook Plant Life Cycle Management Project rider effective January 2014.
These increases were partially offset by:
A $14 million decrease due to lower Indiana recovery of energy efficiency program costs. The decrease in revenue was partially offset by a corresponding decrease in energy efficiency expense items discussed below.
A $10 million decrease in certain cost recovery revenues, including fuel and PJM costs.
Margins from Off-system Sales increased $56 million due to higher market prices and increased sales volumes.
Transmission Revenues increased $9 million primarily due to increased investment in the PJM region.
Other Revenues decreased $16 million primarily due to a decrease in barging. This decrease in barging is a result of River Transportation Division (RTD) no longer serving plants transferred to AGR as a result of corporate separation in Ohio. The decrease in RTD revenue was offset by a corresponding decrease in Other Operation and Maintenance expenses for barging as discussed below.


114


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

Other Operation and Maintenance expenses increased $17 million primarily due to the following:
· Other Operation and Maintenance expenses decreased $1 million primarily due to the following:
·
A $16 million increase in transmission expenses primarily due to increased PJM expenses.
A $13 million increase in nuclear expenses primarily due to a prior year deferral of expenses, as regulatory assets, for future recovery as approved by the IURC effective March 2013.
A $5 million increase in distribution expenses primarily due to metering expenses and maintenance of overhead lines.
A $5 million increase in administrative and general expenses.
These increases were partially offset by:
A $14 million decrease in RTD expenses for barging activities. The decrease in RTD expenses was offset by a corresponding decrease in Other Revenues from barging activities as discussed above.
A $9 million decrease in customer services expense related to energy efficiency. The decrease in expenses was offset by a corresponding decrease in Retail Margins discussed above.
Depreciation and Amortization expenses increased $13 million decrease in RTD expenses for barging activities.  The decrease in RTD expenses was offset by a corresponding decrease in Other Revenues from barging activities discussed above.
This decrease was partially offset by:
●A $9 million increase in nuclear expenses primarily due to a prior year deferral of expenses, as regulatory assets, for future recovery as approved by the IURC effective March 2013.
●A $2 million increase due to increased maintenance of overhead lines.
 ·Depreciation and Amortization expenses increased $9 million primarily due to higher depreciable base.
 ·Income Tax Expense increased $17 million primarily due to an increase in pretax book income.
88
Income Tax Expense increased $10 million primarily due to an increase in pretax book income and the regulatory accounting treatment of state income taxes, partially offset by 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 2013 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 186243 for a discussion of accounting pronouncements.

115
89

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
        
  Three Months Ended March 31,
  2014  2013 
REVENUES     
Electric Generation, Transmission and Distribution $ 614,843  $ 490,603 
Sales to AEP Affiliates   2,284    54,977 
Other Revenues - Affiliated   24,727    35,825 
Other Revenues - Nonaffiliated   -    1,988 
TOTAL REVENUES   641,854    583,393 
        
EXPENSES      
Fuel and Other Consumables Used for Electric Generation   156,643    104,865 
Purchased Electricity for Resale   5,362    41,812 
Purchased Electricity from AEP Affiliates   72,056    101,376 
Other Operation   141,350    145,238 
Maintenance   48,565    45,514 
Depreciation and Amortization   50,031    40,902 
Taxes Other Than Income Taxes   21,823    22,456 
TOTAL EXPENSES   495,830    502,163 
        
OPERATING INCOME   146,024    81,230 
        
Other Income (Expense):      
Interest Income   1,049    2,055 
Allowance for Equity Funds Used During Construction   3,964    5,646 
Interest Expense   (25,633)   (24,211)
        
INCOME BEFORE INCOME TAX EXPENSE   125,404    64,720 
        
Income Tax Expense   38,315    21,263 
        
NET INCOME $ 87,089  $ 43,457 
        
The common stock of I&M is wholly-owned by AEP.
        
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

90


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2014 and 2013
 (in thousands)
(Unaudited)
        
   Three Months Ended March 31,
   2014  2013 
Net Income $ 87,089  $ 43,457 
        
OTHER COMPREHENSIVE INCOME, NET OF TAXES      
Cash Flow Hedges, Net of Tax of $229 and $1,682 in 2014 and 2013, Respectively   425    3,123 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $23 and $94      
 in 2014 and 2013, Respectively   43    176 
        
TOTAL OTHER COMPREHENSIVE INCOME   468    3,299 
        
TOTAL COMPREHENSIVE INCOME $ 87,557  $ 46,756 
        
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
  Three Months Ended Six Months Ended
  June 30, June 30,
  2014 2013 2014 2013
REVENUES        
Electric Generation, Transmission and Distribution $506,997
 $490,301
 $1,121,840
 $980,904
Sales to AEP Affiliates 1,068
 31,335
 3,352
 86,312
Other Revenues – Affiliated 25,262
 26,815
 49,989
 62,640
Other Revenues – Nonaffiliated 549
 1,050
 549
 3,038
TOTAL REVENUES 533,876
 549,501
 1,175,730
 1,132,894
         
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 113,700
 85,030
 270,343
 189,895
Purchased Electricity for Resale 27,086
 36,814
 32,448
 78,626
Purchased Electricity from AEP Affiliates 65,190
 99,547
 137,246
 200,923
Other Operation 146,272
 132,478
 287,622
 277,716
Maintenance 54,246
 50,238
 102,811
 95,752
Depreciation and Amortization 49,446
 45,696
 99,477
 86,598
Taxes Other Than Income Taxes 20,803
 22,165
 42,626
 44,621
TOTAL EXPENSES 476,743
 471,968
 972,573
 974,131
         
OPERATING INCOME 57,133
 77,533
 203,157
 158,763
         
Other Income (Expense):  
  
  
  
Interest Income 1,729
 2,662
 2,778
 4,717
Allowance for Equity Funds Used During Construction 4,804
 4,881
 8,768
 10,527
Interest Expense (23,705) (24,436) (49,338) (48,647)
         
INCOME BEFORE INCOME TAX EXPENSE 39,961
 60,640
 165,365
 125,360
         
Income Tax Expense 12,627
 19,886
 50,942
 41,149
         
NET INCOME $27,334
 $40,754
 $114,423
 $84,211
The common stock of I&M is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.


116


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
91
  Three Months Ended Six Months Ended
  June 30, June 30,
  2014 2013 2014 2013
Net Income $27,334
 $40,754
 $114,423
 $84,211
         
OTHER COMPREHENSIVE INCOME, NET OF TAXES  
  
  
  
Cash Flow Hedges, Net of Tax of $189 and $172 for the Three Months Ended June 30, 2014 and 2013, Respectively, and $418 and $1,854 for the Six Months Ended June 30, 2014 and 2013, Respectively 350
 321
 775
 3,444
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $23 and $95 for the Three Months Ended June 30, 2014 and 2013, Respectively, and $46 and $189 for the Six Months Ended June 30, 2014 and 2013, Respectively 43
 175
 86
 351
         
TOTAL OTHER COMPREHENSIVE INCOME 393
 496
 861
 3,795
         
TOTAL COMPREHENSIVE INCOME $27,727
 $41,250
 $115,284
 $88,006
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

117


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
 Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
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
  
  
  
  
  
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2013$56,584
 $980,896
 $900,182
 $(15,509) $1,922,153
          
Common Stock Dividends 
  
 (75,000)  
 (75,000)
Net Income 
  
 114,423
  
 114,423
Other Comprehensive Income 
  
  
 861
 861
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2014$56,584
 $980,896
 $939,605
 $(14,648) $1,962,437
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

118


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2014 and December 31, 2013
(in thousands)
(Unaudited)
  June 30, December 31,
  2014 2013
CURRENT ASSETS    
Cash and Cash Equivalents $1,658
 $1,317
Advances to Affiliates 13,506
 55,863
Accounts Receivable:    
Customers 60,633
 63,011
Affiliated Companies 50,517
 78,282
Accrued Unbilled Revenues 5,077
 17,293
Miscellaneous 1,581
 5,064
Allowance for Uncollectible Accounts (8) (184)
Total Accounts Receivable 117,800
 163,466
Fuel 52,645
 53,807
Materials and Supplies 206,577
 209,718
Risk Management Assets 17,889
 15,388
Accrued Tax Benefits 28,758
 48,832
Prepayments and Other Current Assets 28,376
 38,103
TOTAL CURRENT ASSETS 467,209
 586,494
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 3,606,655
 3,577,906
Transmission 1,328,541
 1,304,225
Distribution 1,657,901
 1,625,057
Other Property, Plant and Equipment (Including Plant to be Retired, Coal Mining    
and Nuclear Fuel) 1,454,312
 1,421,361
Construction Work in Progress 518,635
 427,164
Total Property, Plant and Equipment 8,566,044
 8,355,713
Accumulated Depreciation, Depletion and Amortization 3,371,379
 3,299,349
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 5,194,665
 5,056,364
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 506,770
 524,114
Spent Nuclear Fuel and Decommissioning Trusts 2,018,506
 1,931,610
Long-term Risk Management Assets 5,407
 11,495
Deferred Charges and Other Noncurrent Assets 130,542
 143,657
TOTAL OTHER NONCURRENT ASSETS 2,661,225
 2,610,876
     
TOTAL ASSETS $8,323,099
 $8,253,734
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

119


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2014 and December 31, 2013
(dollars in thousands)
(Unaudited)
  June 30, December 31,
  2014 2013
CURRENT LIABILITIES    
Advances from Affiliates $47,353
 $—
Accounts Payable:    
General 163,598
 142,219
Affiliated Companies 67,241
 93,773
Long-term Debt Due Within One Year – Nonaffiliated
(June 30, 2014 and December 31, 2013 Amounts Include $83,728 and $107,143, Respectively, Related to DCC Fuel)		 260,728
 294,845
Risk Management Liabilities 3,477
 7,029
Customer Deposits 32,966
 31,103
Accrued Taxes 67,151
 73,292
Accrued Interest 26,961
 27,686
Obligations Under Capital Lease 46,420
 46,210
Other Current Liabilities 137,383
 139,088
TOTAL CURRENT LIABILITIES 853,278
 855,245
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 1,718,313
 1,744,171
Long-term Risk Management Liabilities 2,554
 6,946
Deferred Income Taxes 1,184,067
 1,183,350
Regulatory Liabilities and Deferred Investment Tax Credits 1,170,362
 1,112,645
Asset Retirement Obligations 1,284,364
 1,255,184
Deferred Credits and Other Noncurrent Liabilities 147,724
 174,040
TOTAL NONCURRENT LIABILITIES 5,507,384
 5,476,336
     
TOTAL LIABILITIES 6,360,662
 6,331,581
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
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 939,605
 900,182
Accumulated Other Comprehensive Income (Loss) (14,648) (15,509)
TOTAL COMMON SHAREHOLDER’S EQUITY 1,962,437
 1,922,153
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $8,323,099
 $8,253,734
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

120


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
  Six Months Ended June 30,
  2014 2013
OPERATING ACTIVITIES  
  
Net Income $114,423
 $84,211
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 99,477
 86,598
Deferred Income Taxes 17,499
 51,234
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net 28,358
 (18,283)
Allowance for Equity Funds Used During Construction (8,768) (10,527)
Mark-to-Market of Risk Management Contracts (4,378) 9,096
Amortization of Nuclear Fuel 78,560
 62,625
Fuel Over/Under-Recovery, Net 14,567
 (1,796)
Change in Other Noncurrent Assets (42,263) (2,690)
Change in Other Noncurrent Liabilities 44,269
 3,599
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net 45,666
 9,376
Fuel, Materials and Supplies 4,668
 (17,460)
Accounts Payable (26,859) (48,048)
Accrued Taxes, Net 17,381
 10,250
Other Current Assets 9,815
 12,209
Other Current Liabilities (22,913) (16,764)
Net Cash Flows from Operating Activities 369,502
 213,630
     
INVESTING ACTIVITIES  
  
Construction Expenditures (224,937) (267,201)
Change in Advances to Affiliates, Net 42,357
 (156,140)
Purchases of Investment Securities (508,835) (411,769)
Sales of Investment Securities 482,534
 385,942
Acquisitions of Nuclear Fuel (57,991) (58,900)
Insurance Proceeds Related to Cook Plant Fire —
 72,000
Other Investing Activities 9,299
 3,898
Net Cash Flows Used for Investing Activities (257,573) (432,170)
     
FINANCING ACTIVITIES  
  
Issuance of Long-term Debt – Nonaffiliated 99,419
 348,899
Change in Advances from Affiliates, Net 47,353
 —
Retirement of Long-term Debt – Nonaffiliated (160,292) (103,793)
Principal Payments for Capital Lease Obligations (23,622) (2,791)
Dividends Paid on Common Stock (75,000) (25,000)
Other Financing Activities 554
 677
Net Cash Flows from (Used for) Financing Activities (111,588) 217,992
     
Net Increase (Decrease) in Cash and Cash Equivalents 341
 (548)
Cash and Cash Equivalents at Beginning of Period 1,317
 1,562
Cash and Cash Equivalents at End of Period $1,658
 $1,014
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $42,779
 $44,165
Net Cash Paid (Received) for Income Taxes 13,206
 (27,608)
Noncash Acquisitions Under Capital Leases 3,918
 1,888
Construction Expenditures Included in Current Liabilities as of June 30, 59,759
 44,060
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, 42,076
 41,086
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage 2,444
 —
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

121



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
 
           Accumulated  
           Other  
  Common Paid-in Retained Comprehensive  
     Stock Capital Earnings Income (Loss) Total
TOTAL COMMON SHAREHOLDER'S               
 EQUITY – DECEMBER 31, 2012 $  56,584  $  980,896  $  795,178  $  (28,883) $  1,803,775 
                
Common Stock Dividends         (12,500)      (12,500)
Net Income         43,457       43,457 
Other Comprehensive Income            3,299    3,299 
TOTAL COMMON SHAREHOLDER'S               
 EQUITY – MARCH 31, 2013 $  56,584  $  980,896  $  826,135  $  (25,584) $  1,838,031 
                
TOTAL COMMON SHAREHOLDER'S               
 EQUITY – DECEMBER 31, 2013 $  56,584  $  980,896  $  900,182  $  (15,509) $ 1,922,153 
                
Common Stock Dividends         (25,000)      (25,000)
Net Income         87,089       87,089 
Other Comprehensive Income            468    468 
TOTAL COMMON SHAREHOLDER'S               
 EQUITY – MARCH 31, 2014 $  56,584  $  980,896  $  962,271  $  (15,041) $  1,984,710 
                
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

92


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2014 and December 31, 2013
(in thousands)
(Unaudited)
         
    March 31, December 31,
  2014  2013 
CURRENT ASSETS      
Cash and Cash Equivalents $ 2,288  $ 1,317 
Advances to Affiliates   59,162    55,863 
Accounts Receivable:      
 Customers   52,471    63,011 
 Affiliated Companies   71,359    78,282 
 Accrued Unbilled Revenues   13,999    17,293 
 Miscellaneous   1,259    5,064 
 Allowance for Uncollectible Accounts   (33)   (184)
  Total Accounts Receivable   139,055    163,466 
Fuel   49,365    53,807 
Materials and Supplies   206,820    209,718 
Risk Management Assets   12,558    15,388 
Accrued Tax Benefits   29,792    48,832 
Prepayments and Other Current Assets   27,897    38,103 
TOTAL CURRENT ASSETS   526,937    586,494 
       
PROPERTY, PLANT AND EQUIPMENT      
Electric:      
 Generation   3,583,883    3,577,906 
 Transmission   1,310,169    1,304,225 
 Distribution   1,641,866    1,625,057 
Other Property, Plant and Equipment (Including Plant to be Retired, Coal Mining      
 and Nuclear Fuel)   1,440,408    1,421,361 
Construction Work in Progress   476,734    427,164 
Total Property, Plant and Equipment   8,453,060    8,355,713 
Accumulated Depreciation, Depletion and Amortization   3,337,401    3,299,349 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
   5,115,659    5,056,364 
       
OTHER NONCURRENT ASSETS      
Regulatory Assets   505,750    524,114 
Spent Nuclear Fuel and Decommissioning Trusts   1,962,151    1,931,610 
Long-term Risk Management Assets   9,505    11,495 
Deferred Charges and Other Noncurrent Assets   140,198    143,657 
TOTAL OTHER NONCURRENT ASSETS   2,617,604    2,610,876 
       
TOTAL ASSETS $ 8,260,200  $ 8,253,734 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.
93
     ��   
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
March 31, 2014 and December 31, 2013
(dollars in thousands)
(Unaudited)
 
    March 31, December 31,
    2014  2013 
CURRENT LIABILITIES      
Accounts Payable:      
 General $ 121,516  $ 142,219 
 Affiliated Companies   69,635    93,773 
Long-term Debt Due Within One Year – Nonaffiliated      
 (March 31, 2014 and December 31, 2013 Amounts Include $99,439 and      
 $107,143, Respectively, Related to DCC Fuel)   287,598    294,845 
Risk Management Liabilities   4,134    7,029 
Customer Deposits   31,851    31,103 
Accrued Taxes   83,314    73,292 
Accrued Interest   15,182    27,686 
Obligations Under Capital Leases   48,407    46,210 
Other Current Liabilities   146,801    139,088 
TOTAL CURRENT LIABILITIES   808,438    855,245 
       
NONCURRENT LIABILITIES      
Long-term Debt – Nonaffiliated   1,725,246    1,744,171 
Long-term Risk Management Liabilities   5,378    6,946 
Deferred Income Taxes   1,184,213    1,183,350 
Regulatory Liabilities and Deferred Investment Tax Credits   1,122,812    1,112,645 
Asset Retirement Obligations   1,269,671    1,255,184 
Deferred Credits and Other Noncurrent Liabilities   159,732    174,040 
TOTAL NONCURRENT LIABILITIES   5,467,052    5,476,336 
       
TOTAL LIABILITIES   6,275,490    6,331,581 
       
Rate Matters (Note 4)      
Commitments and Contingencies (Note 5)      
       
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   962,271    900,182 
Accumulated Other Comprehensive Income (Loss)   (15,041)   (15,509)
TOTAL COMMON SHAREHOLDER’S EQUITY   1,984,710    1,922,153 
       
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $ 8,260,200  $ 8,253,734 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

94


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
 
     Three Months Ended March 31,
  2014  2013 
OPERATING ACTIVITIES      
Net Income $ 87,089  $ 43,457 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:      
  Depreciation and Amortization   50,031    40,902 
  Deferred Income Taxes   21,017    26,791 
  Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net   14,821    (5,840)
  Allowance for Equity Funds Used During Construction   (3,964)   (5,646)
  Mark-to-Market of Risk Management Contracts   426    9,238 
  Amortization of Nuclear Fuel   38,049    34,000 
  Fuel Over/Under-Recovery, Net   11,683    417 
  Change in Other Noncurrent Assets   (16,211)   (9,217)
  Change in Other Noncurrent Liabilities   11,505    8,577 
  Changes in Certain Components of Working Capital:      
   Accounts Receivable, Net   24,411    22,531 
   Fuel, Materials and Supplies   7,340    (6,868)
   Accounts Payable   (20,902)   (31,801)
   Accrued Taxes, Net   29,583    14,198 
   Other Current Assets   5,933    8,487 
   Other Current Liabilities   (18,862)   (13,443)
Net Cash Flows from Operating Activities   241,949    135,783 
       
INVESTING ACTIVITIES      
Construction Expenditures   (117,807)   (153,262)
Change in Advances to Affiliates, Net   (3,299)   (205,008)
Purchases of Investment Securities   (164,511)   (184,299)
Sales of Investment Securities   147,700    167,670 
Acquisitions of Nuclear Fuel   (49,420)   (46,739)
Insurance Proceeds Related to Cook Plant Fire   -    72,000 
Other Investing Activities   8,860    3,077 
Net Cash Flows Used for Investing Activities   (178,477)   (346,561)
       
FINANCING ACTIVITIES      
Issuance of Long-term Debt – Nonaffiliated   -    247,771 
Retirement of Long-term Debt – Nonaffiliated   (26,337)   (24,864)
Principal Payments for Capital Lease Obligations   (11,569)   (1,265)
Dividends Paid on Common Stock   (25,000)   (12,500)
Other Financing Activities   405    646 
Net Cash Flows from (Used for) Financing Activities   (62,501)   209,788 
       
Net Increase (Decrease) in Cash and Cash Equivalents   971    (990)
Cash and Cash Equivalents at Beginning of Period   1,317    1,562 
Cash and Cash Equivalents at End of Period $ 2,288  $ 572 
       
SUPPLEMENTARY INFORMATION      
Cash Paid for Interest, Net of Capitalized Amounts $ 34,592  $ 30,116 
Net Cash Paid (Received) for Income Taxes   -    (8,007)
Noncash Acquisitions Under Capital Leases   2,406    1,355 
Construction Expenditures Included in Current Liabilities as of March 31,   56,668    42,430 
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31,   116    1,485 
Expected Reimbursement for Capital Costs of Spent Nuclear Fuel Dry Cask Storage   854    - 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

95

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
 
Page
Number
  
Significant Accounting Matters  133
165
New Accounting PronouncementPronouncements  133
166
Comprehensive Income  134
167
Rate Matters  141
186
Commitments, Guarantees and Contingencies  149
196
Benefit Plans  152
201
Business Segments  153
204
Derivatives and Hedging  154
205
Fair Value Measurements  166
219
Income Taxes  177
233
Financing Activities  178
234
Variable Interest Entities  181
238

122
96




OHIO POWER COMPANY AND SUBSIDIARIES


123
97



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

EXECUTIVE OVERVIEW

Company Overview

As a public utility, OPCo engages in the transmission and distribution of power to 1,464,000 retail customers in the northwestern, central, eastern and southern sections of Ohio. OPCo purchases energy and capacity to serve its remaining generation service customers. Prior to January 1, 2014, OPCo also engaged in the generation of electric power and the subsequent sale of that power to customers. On December 31, 2013, based on FERC and PUCO orders which approved corporate separation of generation assets and associated liabilities, OPCo transferred its generation assets and related generation liabilities at net book value to AGR. In accordance with the PUCO’s corporate separation order, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers. Effective January 1, 2014, OPCo purchases power from both affiliated and nonaffiliated entities, subject to auction requirements and PUCO approval, to meet the energy and capacity needs of customers.

Ormet

Ormet had a contract to purchase power from OPCo through 2018. In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down operations effective immediately. The loss of Ormet's load will not have a material impact on future gross margin.

Regulatory Activity

Ohio Electric Security Plan FilingFilings

2009 –- 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. As of March 31,June 30, 2014, OPCo’s net deferred fuel balance was $426$411 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 balance.balance up to the full amount.

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. This ruling was generally upheld in PUCO rehearing orders in January and March 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the 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 OPCo RPM price collected from CRES providers, which includes reserve margins, iswas approximately $33/$34/MW day through May 2014 and $148/is $150/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR is beingwas collected from customers at $3.50/MWh through May 2014 and will beis currently collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR. As of March 31,June 30, 2014, OPCo’s incurred deferred capacity costs balance was $348$396 million, including debt carrying costs.

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98
In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. In February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. The PUCO also orderedIn May 2014, OPCo to conduct energy-only auctions forconducted an additional 50%energy-only auction for 25% of the SSO load with delivery beginning November 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.  The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned.  Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.  Management believes that these intervenor concerns are without merit.  In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012-2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC.  In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC.

Proposed June 2015 – May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018.  This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to market.  The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo.  Additionally, the application identifies OPCo’s intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected.  Management intends to file this application in the second quarter of 2014.  A hearing at the PUCO in the ESP case is scheduled for June 2014.

If OPCo is ultimately not permitted to fully collect its ESP rates, including the RSR, its deferred fuel balance and its deferred capacity cost, it could reduce future net income and cash flows and impact financial condition.  See “Ohio Electric Security Plan Filing” section of Note 4.

Litigation and Environmental Issues

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2013 Annual Report.  Also, see Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 132.  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 186 for additional discussion of relevant factors.
99
RESULTS OF OPERATIONS

KWh Sales/Degree Days
       
Summary of KWh Energy Sales
 
  Three Months Ended March 31,
 2014  2013 
  (in millions of KWhs)
Retail:     
 Residential  4,731    4,264 
 Commercial  3,579    3,386 
 Industrial  3,473    4,082 
 Miscellaneous  34    35 
Total Retail (a)  11,817    11,767 
      
Wholesale  700    3,044 
      
Total KWhs  12,517    14,811 
       
(a) Represents energy delivered to distribution customers.     

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.

Summary of Heating and Cooling Degree Days
 
  Three Months Ended March 31,
 2014  2013 
  (in degree days)
       
Actual - Heating (a)  2,409    1,971 
Normal - Heating (b)  1,880    1,885 
       
Actual - Cooling (c)  -    - 
Normal - Cooling (b)  3    3 
       
(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.

100

First Quarter of 2014 Compared to First Quarter of 2013
Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income
(in millions)
First Quarter of 2013$ 130 
Changes in Gross Margin:
Retail Margins (219)
Off-system Sales (27)
Transmission Revenues 15 
Other Revenues (14)
Total Change in Gross Margin (245)
Changes in Expenses and Other:
Other Operation and Maintenance 72 
Depreciation and Amortization 33 
Taxes Other Than Income Taxes 10 
Interest and Investment Income 4 
Carrying Costs Income 4 
Interest Expense 17 
Total Change in Expenses and Other 140 
Income Tax Expense 36 
First Quarter of 2014$ 61 

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, purchased electricity and amortization of generation deferrals were as follows:

·
Retail Margins decreased $219 million primarily due to the following:
·A $106 million decrease attributable to purchased power due to the AGR Power Supply Agreement related to the base generation SSO load.
·An $87 million decrease due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
·A $14 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.
These decreases were partially offset by:
·A $15 million increase in revenues associated with the Distribution Investment Recovery Rider and Universal Service Fund (USF) surcharge.  Of these increases, $10 million relate to riders/trackers which have corresponding increases in other expense items below.
·
Margins from Off-system Sales decreased $27 million due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
·Transmission Revenues increased $15 million primarily due to increased transmission revenues from customers who have switched to alternative CRES providers and rate increases for customers in the PJM region.  The increase in transmission revenues related to CRES providers offsets lost revenues included in Retail Margins above.
·
Other Revenues decreased $14 million due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.  This decrease in Other Revenues has a corresponding decrease in Other Operation and Maintenance expense below.

101
Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses decreased $72 million primarily due to the following:
·A $114 million decrease due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
This decrease was partially offset by:
·A $15 million increase in PJM expenses.
·An $8 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 $4 million increase in employee-related expenses.
·A $4 million increase in storm expense.
·A $3 million increase in expense related to the factoring of receivables.
·
Depreciation and Amortization expenses decreased $33 million primarily due to the following:
·A $49 million decrease due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
This decrease was partially offset by:
·A $5 million increase in amortization of securitized regulatory assets and recognition of previously unrecognized equity being recovered through the Deferred Asset Phase-In Rider.  This increase was offset by a corresponding increase in Retail Margins above.
·
A $4 million increase due to carrying charge adjustments as a result of expensing certain gridSMART® capital projects.
·A $3 million increase due to an increase in depreciable base of transmission and distribution assets.
·
Taxes Other Than Income Taxes decreased $10 million due to the following:
·An $18 million decrease due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
This decrease was partially offset by:
·A $6 million increase in property taxes due to increased investment in transmission and distribution assets and increased tax rates.
·A $2 million increase in state excise taxes due to increased metered KWh sales.
·
Interest and Investment Income increased $4 million primarily due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
·
Carrying Costs Income increased $4 million primarily due to increased capacity deferral carrying charges.
·
Interest Expense decreased $17 million primarily due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
·
Income Tax Expense decreased $36 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 2013 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 186 for a discussion of accounting pronouncements.

102

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
       
   Three Months Ended March 31,
  2014  2013 
REVENUES     
Electric Generation, Transmission and Distribution $ 846,906  $ 933,681 
Sales to AEP Affiliates   31,978    285,642 
Other Revenues – Affiliated   -    7,840 
Other Revenues – Nonaffiliated   1,308    6,627 
TOTAL REVENUES   880,192    1,233,790 
       
EXPENSES      
Fuel and Other Consumables Used for Electric Generation   -    409,584 
Purchased Electricity for Resale   79,130    43,185 
Purchased Electricity from AEP Affiliates   314,124    80,381 
Amortization of Generation Deferrals   31,186    - 
Other Operation   151,426    184,187 
Maintenance   34,651    74,295 
Depreciation and Amortization   58,699    92,324 
Taxes Other Than Income Taxes   95,257    105,021 
TOTAL EXPENSES   764,473    988,977 
       
OPERATING INCOME   115,719    244,813 
       
Other Income (Expense):      
Interest Income   3,274    363 
Carrying Costs Income   7,114    3,263 
Allowance for Equity Funds Used During Construction   1,726    1,304 
Interest Expense   (33,007)   (50,173)
       
INCOME BEFORE INCOME TAX EXPENSE   94,826    199,570 
       
Income Tax Expense   34,052    69,796 
       
NET INCOME $ 60,774  $ 129,774 
       
The common stock of OPCo is wholly-owned by AEP.
        
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

103


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
        
   Three Months Ended March 31,
   2014  2013 
Net Income $ 60,774  $ 129,774 
        
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES      
Cash Flow Hedges, Net of Tax of $241 and $574 in 2014 and 2013, Respectively   (448)   1,066 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,760 in 2013   -    3,269 
        
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)   (448)   4,335 
        
TOTAL COMPREHENSIVE INCOME $ 60,326  $ 134,109 
        
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

104


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
      
           Accumulated  
           Other  
  Common Paid-in Retained Comprehensive  
     Stock Capital Earnings Income (Loss) Total
TOTAL COMMON SHAREHOLDER'S               
  EQUITY – DECEMBER 31, 2012 $ 321,201  $ 1,744,099  $ 2,626,134  $ (165,725) $ 4,525,709 
                
Common Stock Dividends         (75,000)      (75,000)
Net Income         129,774       129,774 
Other Comprehensive Income            4,335    4,335 
TOTAL COMMON SHAREHOLDER'S               
  EQUITY –  MARCH 31, 2013 $ 321,201  $ 1,744,099  $ 2,680,908  $ (161,390) $ 4,584,818 
                
TOTAL COMMON SHAREHOLDER'S               
  EQUITY – DECEMBER 31, 2013 $ 321,201  $ 663,782  $ 633,203  $ 7,079  $ 1,625,265 
                
Common Stock Dividends         (25,000)      (25,000)
Net Income         60,774       60,774 
Other Comprehensive Loss            (448)   (448)
TOTAL COMMON SHAREHOLDER'S               
  EQUITY –  MARCH 31, 2014 $ 321,201  $ 663,782  $ 668,977  $ 6,631  $ 1,660,591 
                
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

105


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2014 and December 31, 2013
(in thousands)
(Unaudited)
 
    March 31, December 31,
  2014  2013 
CURRENT ASSETS      
Cash and Cash Equivalents $ 4,780  $ 3,004 
Restricted Cash for Securitized Funding   32,054    19,387 
Advances to Affiliates   -    339,070 
Accounts Receivable:      
 Customers   96,218    67,054 
 Affiliated Companies   72,311    74,771 
 Accrued Unbilled Revenues   49,761    36,353 
 Miscellaneous   747    1,559 
 Allowance for Uncollectible Accounts   (39,602)   (34,984)
  Total Accounts Receivable   179,435    144,753 
Notes Receivable Due Within One Year – Affiliated   178,580    178,580 
Materials and Supplies   55,311    53,711 
Risk Management Assets   3,980    3,082 
Deferred Income Tax Benefits   33,642    36,105 
Accrued Tax Benefits   487    7,109 
Regulatory Asset for Under-Recovered Fuel Costs   26,153    15,829 
Prepayments and Other Current Assets   7,085    6,483 
TOTAL CURRENT ASSETS   521,507    807,113 
       
PROPERTY, PLANT AND EQUIPMENT      
Electric:      
 Transmission   2,030,881    2,011,289 
 Distribution   3,907,852    3,877,532 
Other Property, Plant and Equipment   379,780    364,573 
Construction Work in Progress   188,636    185,428 
Total Property, Plant and Equipment   6,507,149    6,438,822 
Accumulated Depreciation and Amortization   1,986,318    1,973,042 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
   4,520,831    4,465,780 
       
OTHER NONCURRENT ASSETS      
Notes Receivable – Affiliated   118,245    118,245 
Regulatory Assets   1,398,055    1,378,697 
Securitized Assets   126,597    131,582 
Deferred Charges and Other Noncurrent Assets   211,819    260,141 
TOTAL OTHER NONCURRENT ASSETS   1,854,716    1,888,665 
       
TOTAL ASSETS $ 6,897,054  $ 7,161,558 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.
106
         
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
March 31, 2014 and December 31, 2013
(Unaudited)
 
    March 31, December 31,
  2014  2013 
   (in thousands)
CURRENT LIABILITIES      
Advances from Affiliates $ 27,108  $ - 
Accounts Payable:      
 General   128,333    146,307 
 Affiliated Companies   195,954    222,889 
Long-term Debt Due Within One Year – Nonaffiliated        
 (March 31, 2014 and December 31, 2013 Amounts Include $57,137 and      
 $34,936, Respectively, Related to Ohio Phase-in-Recovery Funding)  235,785   438,595 
Accrued Taxes   324,491    429,260 
Accrued Interest   49,854    40,853 
Other Current Liabilities   128,143    144,334 
TOTAL CURRENT LIABILITIES   1,089,668    1,422,238 
       
NONCURRENT LIABILITIES      
Long-term Debt – Nonaffiliated        
 (March 31, 2014 and December 31, 2013 Amounts Include $210,266 and      
 $232,466, Respectively, Related to Ohio Phase-in-Recovery Funding)  2,274,500   2,296,580 
Deferred Income Taxes   1,352,301    1,330,711 
Regulatory Liabilities and Deferred Investment Tax Credits   467,433    435,499 
Employee Benefits and Pension Obligations   28,789    28,329 
Deferred Credits and Other Noncurrent Liabilities   23,772    22,936 
TOTAL NONCURRENT LIABILITIES   4,146,795    4,114,055 
       
TOTAL LIABILITIES   5,236,463    5,536,293 
         
Rate Matters (Note 4)      
Commitments and Contingencies (Note 5)      
       
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   663,782    663,782 
Retained Earnings   668,977    633,203 
Accumulated Other Comprehensive Income (Loss)   6,631    7,079 
TOTAL COMMON SHAREHOLDER’S EQUITY   1,660,591    1,625,265 
       
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $ 6,897,054  $ 7,161,558 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

107


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
 
     Three Months Ended March 31,
  2014  2013 
OPERATING ACTIVITIES      
Net Income $ 60,774  $ 129,774 
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for)      
 Operating Activities:      
  Depreciation and Amortization   58,699    92,324 
  Amortization of Generation Deferrals   31,186    - 
  Deferred Income Taxes   24,917    55,328 
  Carrying Costs Income   (7,114)   (3,263)
  Allowance for Equity Funds Used During Construction   (1,726)   (1,304)
  Mark-to-Market of Risk Management Contracts   (1,060)   12,901 
  Property Taxes   48,743    55,246 
  Fuel Over/Under-Recovery, Net   12,265    9,191 
  Deferral of Ohio Capacity Costs, Net   (56,167)   (49,056)
  Change in Other Noncurrent Assets   (21,285)   14,092 
  Change in Other Noncurrent Liabilities   29,277    1,730 
  Changes in Certain Components of Working Capital:      
   Accounts Receivable, Net   (34,984)   58,235 
   Fuel, Materials and Supplies   (1,600)   (1,388)
   Accounts Payable   (30,911)   (42,749)
   Accrued Taxes, Net   (98,147)   (91,308)
   Other Current Assets   (1,415)   (705)
   Other Current Liabilities   (13,633)   (21,374)
Net Cash Flows from (Used for) Operating Activities   (2,181)   217,674 
       
INVESTING ACTIVITIES      
Construction Expenditures   (100,220)   (131,590)
Change in Restricted Cash for Securitized Funding   (12,668)   - 
Change in Advances to Affiliates, Net   339,070    106,080 
Other Investing Activities   1,162    9,760 
Net Cash Flows from (Used for) Investing Activities   227,344    (15,750)
       
FINANCING ACTIVITIES      
Issuance of Long-term Debt – Affiliated   -    200,000 
Change in Advances from Affiliates, Net   27,108    172,211 
Retirement of Long-term Debt – Nonaffiliated   (225,029)   (500,000)
Principal Payments for Capital Lease Obligations   (1,396)   (2,508)
Dividends Paid on Common Stock   (25,000)   (75,000)
Other Financing Activities   930    760 
Net Cash Flows Used for Financing Activities   (223,387)   (204,537)
       
Net Increase (Decrease) in Cash and Cash Equivalents   1,776    (2,613)
Cash and Cash Equivalents at Beginning of Period   3,004    3,640 
Cash and Cash Equivalents at End of Period $ 4,780  $ 1,027 
       
SUPPLEMENTARY INFORMATION      
Cash Paid for Interest, Net of Capitalized Amounts $ 23,425  $ 50,327 
Net Cash Paid (Received) for Income Taxes   -    (2,390)
Noncash Acquisitions Under Capital Leases   3,324    1,811 
Government Grants Included in Accounts Receivable as of March 31,   -    1,147 
Construction Expenditures Included in Current Liabilities as of March 31,   46,910    69,152 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

108

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

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

Page
Number
Significant Accounting Matters  133
New Accounting Pronouncement  133
Comprehensive Income  134
Rate Matters  141
Commitments, Guarantees and Contingencies  149
Benefit Plans  152
Business Segments  153
Derivatives and Hedging  154
Fair Value Measurements  166
Income Taxes  177
Financing Activities  178
Variable Interest Entities  181

109

PUBLIC SERVICE COMPANY OF OKLAHOMA


110

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

EXECUTIVE OVERVIEW

Regulatory Activity

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity.  This revenue increase includes a proposed increase in depreciation rates of $29 million.  In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three.  The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years.  In April 2014, the OCC Staff and intervenors filed testimony with various recommendations.  A hearing at the OCC is scheduled for June 2014.  See the "2014 Oklahoma Base Rate Case" section of Note 4.
Litigation and Environmental Issues

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2013 Annual Report.  Also, see Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 132.  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 186 for additional discussion of relevant factors.
RESULTS OF OPERATIONS

KWh Sales/Degree Days
       
Summary of KWh Energy Sales
 
  Three Months Ended March 31,
 2014  2013 
  (in millions of KWhs)
Retail:     
 Residential  1,634    1,436 
 Commercial  1,139    1,079 
 Industrial  1,193    1,194 
 Miscellaneous  278    277 
Total Retail  4,244    3,986 
      
Wholesale  227    255 
      
Total KWhs  4,471    4,241 

111
Heating degree days and cooling 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 March 31,
 2014  2013 
  (in degree days)
       
Actual - Heating (a)  1,369    1,089 
Normal - Heating (b)  1,045    1,045 
       
Actual - Cooling (c)  3    5 
Normal - Cooling (b)  15    15 
       
(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.

112

First Quarter of 2014 Compared to First Quarter of 2013
Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income
(in millions)
First Quarter of 2013$ 14 
Changes in Gross Margin:
Transmission Revenues 1 
Total Change in Gross Margin 1 
Changes in Expenses and Other:
Other Operation and Maintenance (7)
Taxes Other Than Income Taxes (2)
Other Income (1)
Total Change in Expenses and Other (10)
Income Tax Expense 3 
First Quarter of 2014$ 8 

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

·
Other Operation and Maintenance expenses increased $7 million primarily due to the following:
·A $6 million increase in transmission expenses primarily due to increased SPP transmission services.
·A $2 million increase in generation plant operation and maintenance expenses.
These increases were partially offset by:
·A $3 million decrease in distribution expenses primarily related to the amortization of the 2007 and 2010 storm deferrals which were fully recovered in 2013.
·
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 2013 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 186 for a discussion of accounting pronouncements.

113

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
        
  Three Months Ended March 31,
  2014  2013 
REVENUES     
Electric Generation, Transmission and Distribution $ 296,710  $ 259,903 
Sales to AEP Affiliates   4,597    1,834 
Other Revenues   78    552 
TOTAL REVENUES   301,385    262,289 
        
EXPENSES      
Fuel and Other Consumables Used for Electric Generation   65,937    43,310 
Purchased Electricity for Resale   79,691    64,655 
Purchased Electricity from AEP Affiliates   11,024    10,216 
Other Operation   58,711    47,807 
Maintenance   24,745    28,572 
Depreciation and Amortization   23,982    24,180 
Taxes Other Than Income Taxes   11,969    9,997 
TOTAL EXPENSES   276,059    228,737 
       
OPERATING INCOME   25,326    33,552 
       
Other Income (Expense):      
Other Income   1,428    2,115 
Interest Expense   (13,317)   (13,340)
       
INCOME BEFORE INCOME TAX EXPENSE   13,437    22,327 
       
Income Tax Expense   4,989    8,634 
       
NET INCOME $ 8,448  $ 13,693 
       
The common stock of PSO is wholly-owned by AEP.      
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

114


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
        
   Three Months Ended March 31,
   2014  2013 
Net Income $ 8,448  $ 13,693 
        
OTHER COMPREHENSIVE LOSS, NET OF TAXES      
Cash Flow Hedges, Net of Tax of $132 and $90 in 2014 and 2013, Respectively   (246)   (167)
        
TOTAL COMPREHENSIVE INCOME $ 8,202  $ 13,526 
        
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

115


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
                   
              Accumulated  
              Other  
     Common Paid-in Retained Comprehensive  
     Stock Capital Earnings Income (Loss) Total
TOTAL COMMON SHAREHOLDER'S               
 EQUITY – DECEMBER 31, 2012 $ 157,230  $ 364,037  $ 388,530  $ 6,481  $ 916,278 
                
Common Stock Dividends         (13,750)      (13,750)
Net Income         13,693       13,693 
Other Comprehensive Loss            (167)   (167)
TOTAL COMMON SHAREHOLDER'S               
 EQUITY – MARCH 31, 2013 $ 157,230  $ 364,037  $ 388,473  $ 6,314  $ 916,054 
                
TOTAL COMMON SHAREHOLDER'S               
 EQUITY – DECEMBER 31, 2013 $ 157,230  $ 364,037  $ 415,076  $ 5,758  $ 942,101 
                
Net Income         8,448       8,448 
Other Comprehensive Loss            (246)   (246)
TOTAL COMMON SHAREHOLDER'S               
 EQUITY – MARCH 31, 2014 $ 157,230  $ 364,037  $ 423,524  $ 5,512  $ 950,303 
                
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

116


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
March 31, 2014 and December 31, 2013
(in thousands)
(Unaudited)
 
    March 31, December 31,
  2014  2013 
CURRENT ASSETS      
Cash and Cash Equivalents $ 1,756  $ 1,277 
Accounts Receivable:      
 Customers   29,384    32,314 
 Affiliated Companies   18,634    30,392 
 Miscellaneous   3,460    3,102 
 Allowance for Uncollectible Accounts   (325)   (462)
  Total Accounts Receivable   51,153    65,346 
Fuel   15,054    15,191 
Materials and Supplies   52,695    52,707 
Risk Management Assets   1,349    1,167 
Deferred Income Tax Benefits   -    7,333 
Accrued Tax Benefits   35,708    21,665 
Regulatory Asset for Under-Recovered Fuel Costs   26,692    3,298 
Prepayments and Other Current Assets   5,994    6,194 
TOTAL CURRENT ASSETS   190,401    174,178 
       
PROPERTY, PLANT AND EQUIPMENT      
Electric:      
 Generation   1,236,105    1,203,221 
 Transmission   727,512    731,312 
 Distribution   2,001,049    1,986,032 
Other Property, Plant and Equipment (Including Plant to be Retired)   411,700    393,026 
Construction Work in Progress   172,949    175,890 
Total Property, Plant and Equipment   4,549,315    4,489,481 
Accumulated Depreciation and Amortization   1,334,507    1,323,522 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
   3,214,808    3,165,959 
       
OTHER NONCURRENT ASSETS      
Regulatory Assets   164,929    156,690 
Employee Benefits and Pension Assets   23,162    22,629 
Deferred Charges and Other Noncurrent Assets   38,197    7,238 
TOTAL OTHER NONCURRENT ASSETS   226,288    186,557 
       
TOTAL ASSETS $ 3,631,497  $ 3,526,694 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.
117
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
March 31, 2014 and December 31, 2013
(Unaudited)
       
    March 31, December 31,
  2014  2013 
   (in thousands)
CURRENT LIABILITIES      
Advances from Affiliates $ 70,119  $ 36,772 
Accounts Payable:      
 General   106,312    150,184 
 Affiliated Companies   45,468    45,427 
Long-term Debt Due Within One Year – Nonaffiliated   34,118    34,115 
Risk Management Liabilities   83    85 
Customer Deposits   45,676    45,379 
Accrued Taxes   44,847    23,442 
Accrued Interest   15,040    12,646 
Other Current Liabilities   80,931    58,992 
TOTAL CURRENT LIABILITIES   442,594    407,042 
       
NONCURRENT LIABILITIES      
Long-term Debt – Nonaffiliated   1,015,675    965,695 
Deferred Income Taxes   848,101    836,556 
Regulatory Liabilities and Deferred Investment Tax Credits   328,224    327,673 
Employee Benefits and Pension Obligations   9,966    10,561 
Deferred Credits and Other Noncurrent Liabilities   36,634    37,066 
TOTAL NONCURRENT LIABILITIES   2,238,600    2,177,551 
       
TOTAL LIABILITIES   2,681,194    2,584,593 
       
       
Rate Matters (Note 4)      
Commitments and Contingencies (Note 5)      
       
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   423,524    415,076 
Accumulated Other Comprehensive Income (Loss)   5,512    5,758 
TOTAL COMMON SHAREHOLDER’S EQUITY   950,303    942,101 
       
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $ 3,631,497  $ 3,526,694 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

118


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
 
     Three Months Ended March 31,
  2014  2013 
OPERATING ACTIVITIES      
Net Income $ 8,448  $ 13,693 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating      
 Activities:      
  Depreciation and Amortization   23,982    24,180 
  Deferred Income Taxes   19,178    20,242 
  Allowance for Equity Funds Used During Construction   (1,431)   (980)
  Mark-to-Market of Risk Management Contracts   (267)   (3,013)
  Property Taxes   (31,260)   (28,730)
  Fuel Over/Under-Recovery, Net   (23,394)   (17,812)
  Change in Regulatory Assets   (8,468)   4,165 
  Change in Other Noncurrent Assets   (1,045)   (3,780)
  Change in Other Noncurrent Liabilities   (2,204)   4,620 
  Changes in Certain Components of Working Capital:      
   Accounts Receivable, Net   14,193    1,665 
   Fuel, Materials and Supplies   149    1,344 
   Accounts Payable   (16,891)   (5,827)
   Accrued Taxes, Net   7,362    6,106 
   Other Current Assets   (395)   1,181 
   Other Current Liabilities   22,401    10,663 
Net Cash Flows from Operating Activities   10,358    27,717 
       
INVESTING ACTIVITIES      
Construction Expenditures   (93,500)   (54,298)
Change in Advances to Affiliates, Net   -    10,558 
Other Investing Activities   776    5,196 
Net Cash Flows Used for Investing Activities   (92,724)   (38,544)
       
FINANCING ACTIVITIES      
Issuance of Long-term Debt – Nonaffiliated   49,975    - 
Change in Advances from Affiliates, Net   33,347    24,004 
Retirement of Long-term Debt – Nonaffiliated   (102)   (99)
Principal Payments for Capital Lease Obligations   (941)   (754)
Dividends Paid on Common Stock   -    (13,750)
Other Financing Activities   566    533 
Net Cash Flows from Financing Activities   82,845    9,934 
       
Net Increase (Decrease) in Cash and Cash Equivalents   479    (893)
Cash and Cash Equivalents at Beginning of Period   1,277    1,367 
Cash and Cash Equivalents at End of Period $ 1,756  $ 474 
       
SUPPLEMENTARY INFORMATION      
Cash Paid for Interest, Net of Capitalized Amounts $ 10,487  $ 10,519 
Net Cash Paid for Income Taxes   67    284 
Noncash Acquisitions Under Capital Leases   904    1,015 
Construction Expenditures Included in Current Liabilities as of March 31,   34,199    19,868 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

119

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  133
New Accounting Pronouncement  133
Comprehensive Income  134
Rate Matters  141
Commitments, Guarantees and Contingencies  149
Benefit Plans  152
Business Segments  153
Derivatives and Hedging  154
Fair Value Measurements  166
Income Taxes  177
Financing Activities  178
Variable Interest Entities  181

120

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

121

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

EXECUTIVE OVERVIEW

Regulatory Activity

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant.  In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013.  The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund.  The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013.  In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant.  If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.  See the “2012 Louisiana Formula Rate Filing” section of Note 4.

2014 Louisiana Formula Rate Filing

In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC.  The filing included a $5 million annual increase to be effective August 2014.  SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchase power agreement attributable to Louisiana customers.  These increases are subject to LPSC staff review.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC.  Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC.  As of March 31, 2014, SWEPCo has incurred $48 million in costs related to these projects.  SWEPCo will seek to recover these project costs from its state commissions and FERC customers.

Litigation and Environmental Issues

In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2013 Annual Report.  Also, see Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 132.  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 186 for additional discussion of relevant factors.
122
RESULTS OF OPERATIONS

KWh Sales/Degree Days
       
Summary of KWh Energy Sales
 
  Three Months Ended March 31,
 2014  2013 
  (in millions of KWhs)
Retail:     
 Residential  1,747    1,494 
 Commercial  1,393    1,279 
 Industrial  1,377    1,259 
 Miscellaneous  20    19 
Total Retail  4,537    4,051 
      
Wholesale  2,279    2,443 
      
Total KWhs  6,816    6,494 

Heating degree days and cooling 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 March 31,
 2014  2013 
  (in degree days)
       
Actual - Heating (a)  994    732 
Normal - Heating (b)  721    728 
       
Actual - Cooling (c)  10    16 
Normal - Cooling (b)  33    33 
       
(a)Western Region heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Western Region cooling degree days are calculated on a 65 degree temperature base.

123

First Quarter of 2014 Compared to First Quarter of 2013
Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income
(in millions)
First Quarter of 2013$ 12 
Changes in Gross Margin:
Retail Margins (a) 24 
Off-system Sales 2 
Transmission Revenues 2 
Total Change in Gross Margin 28 
Changes in Expenses and Other:
Other Operation and Maintenance (12)
Depreciation and Amortization (1)
Taxes Other Than Income Taxes (1)
Other Income 1 
Interest Expense 2 
Total Change in Expenses and Other (11)
Income Tax Expense (6)
First Quarter of 2014$ 23 
(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 $24 million primarily due to the following:
·A $24 million increase primarily due to the Louisiana and Texas rate orders related to the Turk Plant.
·A $6 million increase in weather-related usage primarily due to a 36% increase in heating degree days.
These increases were partially offset by:
·A $4 million decrease primarily due to 2013 fuel recovery adjustments.

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

·
Other Operation and Maintenance expenses increased $12 million primarily due to the following:
·A $6 million increase in transmission expenses primarily due to increased SPP transmission services.
·A $4 million increase in generation plant operation and maintenance expenses.
·
Income Tax Expense increased $6 million primarily due to an increase in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2013 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 186 for a discussion of accounting pronouncements.

124

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
        
  Three Months Ended March 31,
  2014  2013 
REVENUES     
Electric Generation, Transmission and Distribution $ 426,627  $ 381,277 
Sales to AEP Affiliates   13,598    12,709 
Other Revenues   365    331 
TOTAL REVENUES   440,590    394,317 
        
EXPENSES      
Fuel and Other Consumables Used for Electric Generation   145,587    151,358 
Purchased Electricity for Resale   61,165    39,760 
Purchased Electricity from AEP Affiliates   3,766    1,017 
Other Operation   68,537    59,448 
Maintenance   30,411    27,791 
Depreciation and Amortization   45,661    44,882 
Taxes Other Than Income Taxes   20,737    19,422 
TOTAL EXPENSES   375,864    343,678 
       
OPERATING INCOME   64,726    50,639 
       
Other Income (Expense):      
Other Income   1,967    1,054 
Interest Expense   (31,876)   (33,990)
       
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS   34,817    17,703 
       
Income Tax Expense   12,165    6,796 
Equity Earnings of Unconsolidated Subsidiary   310    641 
       
NET INCOME   22,962    11,548 
       
Net Income Attributable to Noncontrolling Interest   1,102    1,090 
       
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $ 21,860  $ 10,458 
       
The common stock of SWEPCo is wholly-owned by AEP.
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

125


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
        
   Three Months Ended March 31,
   2014  2013 
Net Income $ 22,962  $ 11,548 
        
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES      
Cash Flow Hedges, Net of Tax of $270 and $321 in 2014 and 2013, Respectively   502    596 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $126 and $34 in      
 2014 and 2013, Respectively   (234)   (63)
        
TOTAL OTHER COMPREHENSIVE INCOME   268    533 
        
TOTAL COMPREHENSIVE INCOME   23,230    12,081 
        
Total Comprehensive Income Attributable to Noncontrolling Interest   1,102    1,090 
       
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo      
 COMMON SHAREHOLDER $ 22,128  $ 10,991 
        
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

126


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Three Months Ended March 31, 2014 and 2013
(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, 2012 $  135,660  $  674,606  $  1,228,806  $  (17,860) $  261  $  2,021,473 
                   
Common Stock Dividends         (31,250)         (31,250)
Common Stock Dividends – Nonaffiliated               (964)   (964)
Net Income         10,458       1,090    11,548 
Other Comprehensive Income            533       533 
TOTAL EQUITY – MARCH 31, 2013 $  135,660  $  674,606  $  1,208,014  $  (17,327) $  387  $  2,001,340 
                   
TOTAL EQUITY – DECEMBER 31, 2013 $  135,660  $  674,606  $  1,253,617  $  (8,444) $ 478  $ 2,055,917 
                   
Common Stock Dividends         (25,000)         (25,000)
Common Stock Dividends – Nonaffiliated               (1,236)   (1,236)
Net Income         21,860       1,102    22,962 
Other Comprehensive Income            268       268 
TOTAL EQUITY – MARCH 31, 2014 $  135,660  $  674,606  $  1,250,477  $  (8,176) $  344  $  2,052,911 
                   
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

127


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2014 and December 31, 2013
(in thousands)
(Unaudited)
 
     March 31, December 31,
  2014  2013 
CURRENT ASSETS      
Cash and Cash Equivalents $ 17,995  $ 17,241 
   (March 31, 2014 and December 31, 2013 Amounts Include $15,539 and     
   $15,827, Respectively, Related to Sabine)      
Accounts Receivable:      
  Customers   76,416    86,263 
  Affiliated Companies   21,341    22,389 
  Miscellaneous   24,380    27,175 
  Allowance for Uncollectible Accounts   (1,342)   (1,418)
   Total Accounts Receivable   120,795    134,409 
Fuel      
  (March 31, 2014 and December 31, 2013 Amounts Include $36,143 and      
  $37,518, Respectively, Related to Sabine)   116,294    122,026 
Materials and Supplies   75,492    74,862 
Risk Management Assets   1,907    1,179 
Deferred Income Tax Benefits   170,410    177,297 
Regulatory Asset for Under-Recovered Fuel Costs   32,325    17,949 
Prepayments and Other Current Assets   24,786    21,089 
TOTAL CURRENT ASSETS   560,004    566,052 
       
PROPERTY, PLANT AND EQUIPMENT      
Electric:      
  Generation   3,790,809    3,764,429 
  Transmission   1,190,356    1,165,167 
  Distribution   1,850,573    1,843,912 
Other Property, Plant and Equipment (Including Plant to be Retired)      
  (March 31, 2014 and December 31, 2013 Amounts Include $291,571 and      
  $291,556, Respectively, Related to Sabine)   873,458    869,230 
Construction Work in Progress   309,200    281,849 
Total Property, Plant and Equipment   8,014,396    7,924,587 
Accumulated Depreciation and Amortization      
  (March 31, 2014 and December 31, 2013 Amounts Include $138,789 and      
  $134,282, Respectively, Related to Sabine)   2,424,701    2,391,652 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
   5,589,695    5,532,935 
       
OTHER NONCURRENT ASSETS      
Regulatory Assets   367,406    369,905 
Deferred Charges and Other Noncurrent Assets   133,123    92,890 
TOTAL OTHER NONCURRENT ASSETS   500,529    462,795 
       
TOTAL ASSETS $ 6,650,228  $ 6,561,782 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.
128
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 2014 and December 31, 2013
(Unaudited)
 
     March 31, December 31,
  2014  2013 
   (in thousands)
CURRENT LIABILITIES      
Advances from Affiliates $ 117,342  $ 9,180 
Accounts Payable:      
  General   138,177    152,653 
  Affiliated Companies   53,742    56,923 
Long-term Debt Due Within One Year – Nonaffiliated   56,750    3,250 
Customer Deposits   57,065    56,375 
Accrued Taxes   83,946    41,508 
Accrued Interest   18,565    43,996 
Obligations Under Capital Leases   18,220    17,899 
Regulatory Liability for Over-Recovered Fuel Costs   -    7,275 
Other Current Liabilities   61,448    79,622 
TOTAL CURRENT LIABILITIES   605,255    468,681 
       
NONCURRENT LIABILITIES      
Long-term Debt – Nonaffiliated   1,985,046    2,040,082 
Deferred Income Taxes   1,277,745    1,271,478 
Regulatory Liabilities and Deferred Investment Tax Credits   477,469    472,128 
Asset Retirement Obligations   88,866    87,630 
Employee Benefits and Pension Obligations   13,914    14,602 
Obligations Under Capital Leases   102,984    105,086 
Deferred Credits and Other Noncurrent Liabilities   46,038    46,178 
TOTAL NONCURRENT LIABILITIES   3,992,062    4,037,184 
       
TOTAL LIABILITIES   4,597,317    4,505,865 
       
Rate Matters (Note 4)      
Commitments and Contingencies (Note 5)      
       
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   1,250,477    1,253,617 
Accumulated Other Comprehensive Income (Loss)   (8,176)   (8,444)
TOTAL COMMON SHAREHOLDER’S EQUITY   2,052,567    2,055,439 
       
Noncontrolling Interest   344    478 
       
TOTAL EQUITY   2,052,911    2,055,917 
       
TOTAL LIABILITIES AND EQUITY $ 6,650,228  $ 6,561,782 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

129


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)
 
     Three Months Ended March 31,
  2014  2013 
OPERATING ACTIVITIES      
Net Income $ 22,962  $ 11,548 
Adjustments to Reconcile Net Income to Net Cash Flows from      
  Operating Activities:      
  Depreciation and Amortization   45,661    44,882 
  Deferred Income Taxes   11,351    25,583 
  Allowance for Equity Funds Used During Construction   (2,081)   (1,024)
  Mark-to-Market of Risk Management Contracts   (825)   (293)
  Property Taxes   (37,511)   (36,161)
  Fuel Over/Under-Recovery, Net   (21,651)   (7,496)
  Change in Other Noncurrent Assets   3,963    (1,245)
  Change in Other Noncurrent Liabilities   2,914    4,953 
  Changes in Certain Components of Working Capital:      
   Accounts Receivable, Net   13,614    11,654 
   Fuel, Materials and Supplies   5,102    3,303 
   Accounts Payable   (9,410)   (12,658)
   Customer Deposits   690    (14,202)
   Accrued Taxes, Net   42,596    27,994 
   Accrued Interest   (25,431)   (25,447)
   Other Current Assets   (4,663)   (638)
   Other Current Liabilities   (18,813)   (13,551)
Net Cash Flows from Operating Activities   28,468    17,202 
       
INVESTING ACTIVITIES      
Construction Expenditures   (105,165)   (97,786)
Change in Advances to Affiliates, Net   -    126,944 
Other Investing Activities   1,046    (1,108)
Net Cash Flows from (Used for) Investing Activities   (104,119)   28,050 
       
FINANCING ACTIVITIES      
Credit Facility Borrowings   -    17,091 
Change in Advances from Affiliates, Net   108,162    - 
Retirement of Long-term Debt – Nonaffiliated   (1,625)   (1,625)
Credit Facility Repayments   -    (19,694)
Principal Payments for Capital Lease Obligations   (4,470)   (4,225)
Dividends Paid on Common Stock   (25,000)   (31,250)
Dividends Paid on Common Stock – Nonaffiliated   (1,236)   (964)
Other Financing Activities   574    522 
Net Cash Flows from (Used for) Financing Activities   76,405    (40,145)
       
Net Increase in Cash and Cash Equivalents   754    5,107 
Cash and Cash Equivalents at Beginning of Period   17,241    2,036 
Cash and Cash Equivalents at End of Period $ 17,995  $ 7,143 
       
SUPPLEMENTARY INFORMATION      
Cash Paid for Interest, Net of Capitalized Amounts $ 55,123  $ 55,626 
Net Cash Paid (Received) for Income Taxes   734    (8,387)
Noncash Acquisitions Under Capital Leases   2,824    2,454 
Construction Expenditures Included in Current Liabilities as of March 31,   53,628    40,990 
       
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

130

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  133
New Accounting Pronouncement  133
Comprehensive Income  134
Rate Matters  141
Commitments, Guarantees and Contingencies  149
Benefit Plans  152
Business Segments  153
Derivatives and Hedging  154
Fair Value Measurements  166
Income Taxes  177
Financing Activities  178
Variable Interest Entities  181
131
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 MattersAPCo, I&M, OPCo, PSO, SWEPCo  133
New Accounting PronouncementAPCo, I&M, OPCo, PSO, SWEPCo  133
Comprehensive IncomeAPCo, I&M, OPCo, PSO, SWEPCo  134
Rate MattersAPCo, I&M, OPCo, PSO, SWEPCo  141
Commitments, Guarantees and ContingenciesAPCo, I&M, OPCo, PSO, SWEPCo  149
Benefit PlansAPCo, I&M, OPCo, PSO, SWEPCo  152
Business SegmentsAPCo, I&M, OPCo, PSO, SWEPCo  153
Derivatives and HedgingAPCo, I&M, OPCo, PSO, SWEPCo  154
Fair Value MeasurementsAPCo, I&M, OPCo, PSO, SWEPCo  166
Income TaxesAPCo, I&M, OPCo, PSO, SWEPCo  177
Financing ActivitiesAPCo, I&M, OPCo, PSO, SWEPCo  178
Variable Interest EntitiesAPCo, I&M, OPCo, PSO, SWEPCo  181

132

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 months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014.

Revenue Recognition

Electricity Supply and Delivery Activities – Transactions with PJM

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services.  The Registrant Subsidiaries recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.

APCo and I&M sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load.  These power sales and purchases for each subsidiary’s retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenue on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income.  Upon termination of the Interconnection Agreement, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices.
2.  NEW ACCOUNTING PRONOUNCEMENT

Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business.  The following summary of a final pronouncement will impact the financial statements.

ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08)

In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations.  Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held for sale or is disposed.  The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations.  This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date.  Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014.  If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management plans to adopt ASU 2014-08 effective January 1, 2015.

133
3.  COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 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 March 31, 2014
             
    Cash Flow Hedges      
       Interest Rate and Pension   
    Commodity Foreign Currency and OPEB Total
    (in thousands)
 Balance in AOCI as of December 31, 2013$ 94  $ 3,090  $ (233) $ 2,951 
 Change in Fair Value Recognized in AOCI  1,583    -    -    1,583 
 Amounts Reclassified from AOCI  (1,590)   253    (333)   (1,670)
 Net Current Period Other           
   Comprehensive Income  (7)   253    (333)   (87)
 Balance in AOCI as of March 31, 2014$ 87  $ 3,343  $ (566) $ 2,864 
               
APCo           
 Changes in Accumulated Other Comprehensive Income (Loss) by Component
 For the Three Months Ended March 31, 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  794    (1)   -    793 
 Amounts Reclassified from AOCI  211    254    358    823 
 Net Current Period Other           
   Comprehensive Income  1,005    253    358    1,616 
 Balance in AOCI as of March 31, 2013$ 361  $ 2,330  $ (30,973) $ (28,282)

134
I&M           
 Changes in Accumulated Other Comprehensive Income (Loss) by Component
 For the Three Months Ended March 31, 2014
             
    Cash Flow Hedges      
       Interest Rate and Pension   
    Commodity Foreign Currency and OPEB Total
    (in thousands)
 Balance in AOCI as of December 31, 2013$ 46  $ (15,976) $ 421  $ (15,509)
 Change in Fair Value Recognized in AOCI  1,062    -    -    1,062 
 Amounts Reclassified from AOCI  (1,047)   410    43    (594)
 Net Current Period Other           
   Comprehensive Income  15    410    43    468 
 Balance in AOCI as of March 31, 2014$ 61  $ (15,566) $ 464  $ (15,041)
               
I&M           
 Changes in Accumulated Other Comprehensive Income (Loss) by Component
 For the Three Months Ended March 31, 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  532    2,249    -    2,781 
 Amounts Reclassified from AOCI  150    192    176    518 
 Net Current Period Other           
   Comprehensive Income  682    2,441    176    3,299 
 Balance in AOCI as of March 31, 2013$ 236  $ (17,206) $ (8,614) $ (25,584)

OPCo
 Changes in Accumulated Other Comprehensive Income (Loss) by Component
 For the Three Months Ended March 31, 2014
             
    Cash Flow Hedges      
       Interest Rate and Pension   
    Commodity Foreign Currency and OPEB Total
    (in thousands)
 Balance in AOCI as of December 31, 2013$ 105  $ 6,974  $ -  $ 7,079 
 Change in Fair Value Recognized in AOCI  -    -    -    - 
 Amounts Reclassified from AOCI  (105)   (343)   -    (448)
 Net Current Period Other           
   Comprehensive Income  (105)   (343)   -    (448)
 Balance in AOCI as of March 31, 2014$ -  $ 6,631  $ -  $ 6,631 
               
OPCo
 Changes in Accumulated Other Comprehensive Income (Loss) by Component
 For the Three Months Ended March 31, 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  1,102    -    -    1,102 
 Amounts Reclassified from AOCI  304    (340)   3,269    3,233 
 Net Current Period Other           
   Comprehensive Income  1,406    (340)   3,269    4,335 
 Balance in AOCI as of March 31, 2013$ 494  $ 7,755  $ (169,639) $ (161,390)

135
PSO           
 Changes in Accumulated Other Comprehensive Income (Loss) by Component
 For the Three Months Ended March 31, 2014
          
    Cash Flow Hedges   
       Interest Rate and   
    Commodity Foreign Currency Total
            
    (in thousands)
 Balance in AOCI as of December 31, 2013$ 57  $ 5,701  $ 5,758 
 Change in Fair Value Recognized in AOCI  -    -    - 
 Amounts Reclassified from AOCI  (57)   (189)   (246)
 Net Current Period Other        
   Comprehensive Income  (57)   (189)   (246)
 Balance in AOCI as of March 31, 2014$ -  $ 5,512  $ 5,512 
            
PSO           
 Changes in Accumulated Other Comprehensive Income (Loss) by Component
 For the Three Months Ended March 31, 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  36    -    36 
 Amounts Reclassified from AOCI  (13)   (190)   (203)
 Net Current Period Other        
   Comprehensive Income  23    (190)   (167)
 Balance in AOCI as of March 31, 2013$ 44  $ 6,270  $ 6,314 

SWEPCo
 Changes in Accumulated Other Comprehensive Income (Loss) by Component
 For the Three Months Ended March 31, 2014
             
    Cash Flow Hedges      
       Interest Rate and Pension   
    Commodity Foreign Currency and OPEB Total
    (in thousands)
 Balance in AOCI as of December 31, 2013$ 66  $ (13,304) $ 4,794  $ (8,444)
 Change in Fair Value Recognized in AOCI  -    -    -    - 
 Amounts Reclassified from AOCI  (66)   568    (234)   268 
 Net Current Period Other           
   Comprehensive Income  (66)   568    (234)   268 
 Balance in AOCI as of March 31, 2014$ -  $ (12,736) $ 4,560  $ (8,176)
               
SWEPCo
 Changes in Accumulated Other Comprehensive Income (Loss) by Component
 For the Three Months Ended March 31, 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  44    -    -    44 
 Amounts Reclassified from AOCI  (15)   567    (63)   489 
 Net Current Period Other           
   Comprehensive Income  29    567    (63)   533 
 Balance in AOCI as of March 31, 2013$ 51  $ (15,004) $ (2,374) $ (17,327)

136
Reclassifications from Accumulated Other Comprehensive Income

The following tables provide details of reclassifications from AOCI for the three months ended March 31, 2014 and 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 March 31, 2014 and 2013
        
     Amount of (Gain) Loss
     Reclassified from AOCI
          
     Three Months Ended March 31,
     2014  2013 
 Gains and Losses on Cash Flow Hedges (in thousands)
 Commodity:      
   Electric Generation, Transmission and Distribution Revenues $ -  $��20 
   Purchased Electricity for Resale   (462)   57 
   Other Operation Expense   (10)   (11)
   Maintenance Expense   (20)   (16)
   Property, Plant and Equipment   (17)   (14)
   Regulatory Assets/(Liabilities), Net (a)   (1,937)   289 
 Subtotal - Commodity   (2,446)   325 
          
 Interest Rate and Foreign Currency:      
   Interest Expense   390    390 
 Subtotal - Interest Rate and Foreign Currency   390    390 
          
 Reclassifications from AOCI, before Income Tax (Expense) Credit   (2,056)   715 
 Income Tax (Expense) Credit   (719)   250 
 Reclassifications from AOCI, Net of Income Tax (Expense) Credit   (1,337)   465 
        
 Pension and OPEB      
 Amortization of Prior Service Cost (Credit)   (1,282)   (1,282)
 Amortization of Actuarial (Gains)/Losses   770    1,833 
 Reclassifications from AOCI, before Income Tax (Expense) Credit   (512)   551 
 Income Tax (Expense) Credit   (179)   193 
 Reclassifications from AOCI, Net of Income Tax (Expense) Credit   (333)   358 
          
 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,670) $ 823 

137
I&M   
 Reclassifications from Accumulated Other Comprehensive Income (Loss)
 For the Three Months Ended March 31, 2014 and 2013
          
     Amount of (Gain) Loss
   Reclassified from AOCI
         
     Three Months Ended March 31,
     2014  2013 
 Gains and Losses on Cash Flow Hedges (in thousands)
 Commodity:      
   Electric Generation, Transmission and Distribution Revenues $ -  $ 52 
   Purchased Electricity for Resale   (717)   149 
   Other Operation Expense   (7)   (7)
   Maintenance Expense   (7)   (7)
   Property, Plant and Equipment   (10)   (7)
   Regulatory Assets/(Liabilities), Net (a)   (870)   50 
 Subtotal - Commodity   (1,611)   230 
          
 Interest Rate and Foreign Currency:      
   Interest Expense   631    296 
 Subtotal - Interest Rate and Foreign Currency   631    296 
          
 Reclassifications from AOCI, before Income Tax (Expense) Credit   (980)   526 
 Income Tax (Expense) Credit   (343)   184 
 Reclassifications from AOCI, Net of Income Tax (Expense) Credit   (637)   342 
        
 Pension and OPEB      
 Amortization of Prior Service Cost (Credit)   (199)   (199)
 Amortization of Actuarial (Gains)/Losses   265    469 
 Reclassifications from AOCI, before Income Tax (Expense) Credit   66    270 
 Income Tax (Expense) Credit   23    94 
 Reclassifications from AOCI, Net of Income Tax (Expense) Credit   43    176 
          
 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (594) $ 518 

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OPCo   
 Reclassifications from Accumulated Other Comprehensive Income (Loss)
 For the Three Months Ended March 31, 2014 and 2013
          
     Amount of (Gain) Loss
   Reclassified from AOCI
         
     Three Months Ended March 31,
     2014  2013 
 Gains and Losses on Cash Flow Hedges (in thousands)
 Commodity:      
   Electric Generation, Transmission and Distribution Revenues $ -  $ 134 
   Purchased Electricity for Resale   -    382 
   Other Operation Expense   (11)   (18)
   Maintenance Expense   (11)   (12)
   Property, Plant and Equipment   (18)   (19)
   Regulatory Assets/(Liabilities), Net (a)   (122)   - 
 Subtotal - Commodity   (162)   467 
          
 Interest Rate and Foreign Currency:      
   Depreciation and Amortization Expense   (3)   2 
   Interest Expense   (524)   (524)
 Subtotal - Interest Rate and Foreign Currency   (527)   (522)
          
 Reclassifications from AOCI, before Income Tax (Expense) Credit   (689)   (55)
 Income Tax (Expense) Credit   (241)   (19)
 Reclassifications from AOCI, Net of Income Tax (Expense) Credit   (448)   (36)
        
 Pension and OPEB      
 Amortization of Prior Service Cost (Credit)   -    (1,468)
 Amortization of Actuarial (Gains)/Losses   -    6,497 
 Reclassifications from AOCI, before Income Tax (Expense) Credit   -    5,029 
 Income Tax (Expense) Credit   -    1,760 
 Reclassifications from AOCI, Net of Income Tax (Expense) Credit   -    3,269 
          
 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (448) $ 3,233 

PSO   
 Reclassifications from Accumulated Other Comprehensive Income (Loss)
 For the Three Months Ended March 31, 2014 and 2013
        
     Amount of (Gain) Loss
     Reclassified from AOCI
         
     Three Months Ended March 31,
     2014  2013 
 Gains and Losses on Cash Flow Hedges (in thousands)
 Commodity:      
   Other Operation Expense $ (8) $ (9)
   Maintenance Expense   (9)   (4)
   Property, Plant and Equipment   (13)   (7)
   Regulatory Assets/(Liabilities), Net (a)   (58)   - 
 Subtotal - Commodity   (88)   (20)
          
 Interest Rate and Foreign Currency:      
   Interest Expense   (292)   (292)
 Subtotal - Interest Rate and Foreign Currency   (292)   (292)
          
 Reclassifications from AOCI, before Income Tax (Expense) Credit   (380)   (312)
 Income Tax (Expense) Credit   (134)   (109)
 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (246) $ (203)

139
SWEPCo   
 Reclassifications from Accumulated Other Comprehensive Income (Loss)
 For the Three Months Ended March 31, 2014 and 2013
        
     Amount of (Gain) Loss
     Reclassified from AOCI
         
     Three Months Ended March 31,
     2014  2013 
 Gains and Losses on Cash Flow Hedges (in thousands)
 Commodity:      
   Other Operation Expense $ (13) $ (10)
   Maintenance Expense   (10)   (6)
   Property, Plant and Equipment   (11)   (7)
   Regulatory Assets/(Liabilities), Net (a)   (67)   - 
 Subtotal - Commodity   (101)   (23)
          
 Interest Rate and Foreign Currency:      
   Interest Expense   872    872 
 Subtotal - Interest Rate and Foreign Currency   872    872 
          
 Reclassifications from AOCI, before Income Tax (Expense) Credit   771    849 
 Income Tax (Expense) Credit   269    297 
 Reclassifications from AOCI, Net of Income Tax (Expense) Credit   502    552 
        
 Pension and OPEB      
 Amortization of Prior Service Cost (Credit)   (478)   (445)
 Amortization of Actuarial (Gains)/Losses   118    348 
 Reclassifications from AOCI, before Income Tax (Expense) Credit   (360)   (97)
 Income Tax (Expense) Credit   (126)   (34)
 Reclassifications from AOCI, Net of Income Tax (Expense) Credit   (234)   (63)
          
 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 268  $ 489 

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

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4.  RATE MATTERS

As discussed in the 2013 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 2013 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 2014 and updates the 2013 Annual Report.

Regulatory Assets Not Yet Being Recovered

     APCo
     March 31, December 31,
     2014  2013 
 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  $ 65,206 
  IGCC Pre-Construction Costs   20,528    - 
  Expanded Net Energy Charge - Coal Inventory   18,818    20,528 
  Mountaineer Carbon Capture and Storage      
   Product Validation Facility   13,264    13,264 
  Virginia Demand Response Program Costs   5,897    5,012 
  Transmission Agreement Phase-In   3,450    3,313 
  Virginia Environmental Rate Adjustment Clause   1,941    2,440 
  Mountaineer Carbon Capture and Storage      
   Commercial Scale Facility   1,287    1,287 
  Other Regulatory Assets Not Yet Being Recovered   513    168 
 Total Regulatory Assets Not Yet Being Recovered $ 130,904  $ 111,218 

     I&M
     March 31, December 31,
     2014  2013 
 Noncurrent Regulatory Assets (in thousands)
 Regulatory assets not yet being recovered pending future proceedings:      
          
 Regulatory Assets Currently Not Earning a Return      
  Indiana Under-Recovered Capacity Costs $ 28,149  $ 21,945 
  Cook Plant Turbine   4,238    3,452 
  Stranded Costs on Abandoned Plants   3,897    3,896 
  Storm Related Costs   751    1,836 
  Indiana Deferred Cook Plant Life Cycle Management Project Costs   -    4,093 
  Other Regulatory Assets Not Yet Being Recovered   694    164 
 Total Regulatory Assets Not Yet Being Recovered $ 37,729  $ 35,386 

     OPCo
     March 31, December 31,
     2014  2013 
 Noncurrent Regulatory Assets (in thousands)
 Regulatory assets not yet being recovered pending future proceedings:      
          
 Regulatory Assets Currently Earning a Return      
  Economic Development Rider $ -  $ 13,854 
 Regulatory Assets Currently Not Earning a Return      
  Ormet Special Rate Recovery Mechanism   10,483    35,631 
  Storm Related Costs   1,635    57,589 
 Total Regulatory Assets Not Yet Being Recovered $ 12,118  $ 107,074 

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     PSO
     March 31, December 31,
     2014  2013 
 Noncurrent Regulatory Assets (in thousands)
 Regulatory assets not yet being recovered pending future proceedings:      
          
 Regulatory Assets Currently Not Earning a Return      
  Storm Related Costs $ 19,093  $ 18,743 
  Other Regulatory Assets Not Yet Being Recovered   1,079    845 
 Total Regulatory Assets Not Yet Being Recovered $ 20,172  $ 19,588 

     SWEPCo
     March 31, December 31,
     2014  2013 
 Noncurrent Regulatory Assets (in thousands)
 Regulatory assets not yet being recovered pending future proceedings:      
          
 Regulatory Assets Currently Not Earning a Return      
  Rate Case Expenses $ 7,930  $ 7,934 
  Mountaineer Carbon Capture and Storage      
   Commercial Scale Facility   1,143    1,143 
  Other Regulatory Assets Not Yet Being Recovered   2,025    1,951 
 Total Regulatory Assets Not Yet Being Recovered $ 11,098  $ 11,028 

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 Filings

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 March 31, 2014, OPCo’s net deferred fuel balance was $426 million, excluding unrecognized equity carrying costs.  In February 2014, the Supreme Court of Ohio affirmed the PUCO’s decision and rejected all appeals filed by the OCC and the IEU.  In February 2014, the IEU filed for reconsideration of the Supreme Court of Ohio decision.

In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012.  The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin.  In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate.  In November 2012, the IEU and the OCC filed appeals regarding the PUCO decision in the PIRR proceeding.  These appeals principally argued that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo’s
142
net deferred fuel balance up to the total balance.  These intervenors’ appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of March 31, 2014, could reduce carrying costs by $30 million including $16 million of unrecognized equity carrying costs.  A decision from the Supreme Court of Ohio is pending.

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

June 2012 – May 2015 ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015.  This ruling 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 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 OPCo RPM price, which includes reserve margins, is approximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.
As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs.  As of March 31, 2014, OPCo’s incurred deferred capacity costs balance of $348 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

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

In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications.  The modifications include the delay of the energy auctions that were originally ordered in the ESP order.  As ordered, in February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50%25% of the SSO load with delivery beginning November 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. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 –- 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In May 2014, an independent auditor was selected by the PUCO and an audit of the recovery of the fixed fuel costs began in June 2014. A final audit report is expected in the third quarter of 2014.

Proposed June 2015 –- May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders including the Distribution Investment Rider, effective June 2015 through May 2018. This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to market.competitively procured SSO supply. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation
143
through OPCo. The proposal also includes a purchased power agreement rider (PPA) that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based purchase power agreement. Additionally, the application identifies OPCo’s intention to submitin July 2014, OPCo submitted a separate application to continue the RSR established in the June 2012 –- May 2015 ESP in whichto collect the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. Management intends to file this application inIn May 2014, intervenors and the second quarterPUCO staff filed testimony that provided various recommendations including the rejection and/or modification of 2014.  A hearingvarious riders, including the Distribution Investment Rider and the proposed PPA. Hearings at the PUCO in the ESP case is scheduled forwere held in June 2014.

If OPCo is ultimately not permitted to fully collect its ESP rates, including the RSR, its deferred fuel balance and its deferred capacity cost, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filings” section of OPCo Rate Matters in Note 4.

Litigation and Environmental Issues

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 164. 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 243 for additional discussion of relevant factors.

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RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in millions of KWhs)
Retail: 
  
  
  
Residential2,945
 3,000
 7,676
 7,264
Commercial3,545
 3,506
 7,124
 6,892
Industrial3,702
 4,203
 7,175
 8,285
Miscellaneous28
 27
 62
 62
Total Retail (a)10,220
 10,736
 22,037
 22,503
        
Wholesale453
(b)2,417
 1,152
(b)5,461
        
Total KWhs10,673
 13,153
 23,189
 27,964

(a)Represents energy delivered to distribution customers.
(b)Ohio's contractually obligated purchases of OVEC power sold into PJM.

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.

Summary of Heating and Cooling Degree Days
  Three Months Ended Six Months Ended
  June 30, June 30,
  2014 2013 2014 2013
  (in degree days)
Actual - Heating (a) 130
 193
 2,539
 2,164
Normal - Heating (b) 187
 190
 2,067
 2,075
         
Actual - Cooling (c) 362
 346
 362
 346
Normal - Cooling (b) 280
 277
 283
 280

(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.

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Second Quarter of 2014 Compared to Second Quarter of 2013
Reconciliation of Second Quarter of 2013 to Second Quarter of 2014
Net Income
(in millions)
   
Second Quarter of 2013 $21
   
Changes in Gross Margin:  
Retail Margins (209)
Off-system Sales (27)
Transmission Revenues 34
Other Revenues (9)
Total Change in Gross Margin (211)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 30
Asset Impairments and Other Related Charges 154
Depreciation and Amortization 51
Taxes Other Than Income Taxes 16
Interest and Investment Income 2
Carrying Costs Income 3
Interest Expense 15
Total Change in Expenses and Other 271
   
Income Tax Expense (24)
   
Second Quarter of 2014 $57

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, purchased electricity and amortization of generation deferrals were as follows:

Retail Margins decreased $209 million primarily due to the following:
A $91 million decrease due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
An $87 million decrease attributable to purchased power due to the AGR Power Supply Agreement related to the base generation SSO load.
A $7 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.
These decreases were partially offset by:
A $14 million increase in revenues primarily associated with the Distribution Investment Rider and Universal Service Fund (USF) surcharge. Of these increases, $2 million relate to riders/trackers which have corresponding increases in other expense items below.
A $13 million increase in revenues associated with the Storm Damage Recovery Rider. This increase in Retail Margins is offset by an increase in Other Operation and Maintenance below.
Margins from Off-system Sales decreased $27 million due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
Transmission Revenues increased $34 million primarily due to increased transmission investment, increased transmission revenues due to customers who have switched to alternative CRES providers and rate increases for customers in the PJM region.  The increase in transmission revenues related to CRES providers primarily offsets lost revenues included in Retail Margins above.

127


Other Revenues decreased $9 million due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013. This decrease in Other Revenues has a corresponding decrease in Other Operation and Maintenance below.

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

Other Operation and Maintenance expenses decreased $30 million primarily due to the following:
A $95 million decrease due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
This decrease was partially offset by:
A $38 million increase in PJM expenses. This increase was offset by a corresponding increase in Retail Margins above.
A $13 million increase due to the amortization of 2012 deferred storm expenses and related carrying charges being recovered through the Storm Damage Recovery Rider. This increase was offset by a corresponding increase in Retail Margins above.
A $4 million increase in employee-related expenses.
A $3 million increase in transmission vegetation management expenses.
Asset Impairments and Other Related Charges decreased $154 million primarily due to the 2013 impairment of Muskingum River Plant, Unit 5.
Depreciation and Amortization expenses decreased $51 million primarily due to the following:
A $53 million decrease due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
This decrease was partially offset by:
A $5 million increase in amortization of securitized assets being recovered through the Deferred Asset Phase-In Rider. This increase was offset by a corresponding increase in Retail Margins above.
Taxes Other Than Income Taxes decreased $16 million primarily due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
Interest Expense decreased $15 million primarily due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
Income Tax Expense increased $24 million primarily due to an increase in pretax book income.


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Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013
Reconciliation of Six Months Ended June 30, 2013 to Six Months Ended June 30, 2014
Net Income
(In Millions)
   
Six Months Ended June 30, 2013 $151
   
Changes in Gross Margin:  
Retail Margins (428)
Off-system Sales (54)
Transmission Revenues 50
Other Revenues (23)
Total Change in Gross Margin (455)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 103
Asset Impairments and Other Related Charges 154
Depreciation and Amortization 84
Taxes Other Than Income Taxes 26
Interest and Investment Income 4
Carrying Costs Income 7
Interest Expense 32
Total Change in Expenses and Other 410
   
Income Tax Expense 11
   
Six Months Ended June 30, 2014 $117

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, purchased electricity and amortization of generation deferrals were as follows:

Retail Margins decreased $428 million primarily due to the following:
A $192 million decrease attributable to purchased power due to the AGR Power Supply Agreement related to the base generation SSO load.
A $179 million decrease due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
A $21 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.
These decreases were partially offset by:
A $28 million increase in revenues primarily associated with the Distribution Investment Rider and Universal Service Fund (USF) surcharge. Of these increases, $12 million relate to riders/trackers which have corresponding increases in other expense items below.
A $13 million increase in revenues associated with the Storm Damage Recovery Rider. This increase in Retail Margins is offset by an increase in Other Operation and Maintenance expenses below.
Margins from Off-system Sales decreased $54 million due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
Transmission Revenues increased $50 million primarily due to increased transmission investment, increased transmission revenues due to customers who have switched to alternative CRES providers and rate increases for customers in the PJM region.  The increase in transmission revenues related to CRES providers primarily offsets lost revenues included in Retail Margins above.

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Other Revenues decreased $23 million due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013. This decrease in Other Revenues has a corresponding decrease in Other Operation and Maintenance expenses below.

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

Other Operation and Maintenance expenses decreased $103 million primarily due to the following:
A $209 million decrease due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
This decrease was partially offset by:
A $54 million increase in PJM expenses. This increase was offset by a corresponding increase in Retail Margins above.
A $13 million increase due to the amortization of 2012 deferred storm expenses and related carrying charges being recovered through the Storm Damage Recovery Rider. This increase was offset by a corresponding increase in Retail Margins above.
A $10 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.
An $8 million increase in employee-related expenses.
Asset Impairments and Other Related Charges decreased $154 million primarily due to the 2013 impairment of Muskingum River Plant, Unit 5.
Depreciation and Amortization expenses decreased $84 million primarily due to the following:
A $100 million decrease due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
This decrease was partially offset by:
A $10 million increase in amortization of securitized assets being recovered through the Deferred Asset Phase-In Rider. This increase was offset by a corresponding increase in Retail Margins above.
Taxes Other Than Income Taxes decreased $26 million due to the following:
A $37 million decrease due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
This decrease was partially offset by:
An $8 million increase in property taxes due to increased investment in transmission and distribution assets and increased tax rates.
Carrying Costs Income increased $7 million primarily due to increased capacity deferral carrying charges.
Interest Expense decreased $32 million primarily due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
Income Tax Expense decreased $11 million primarily due to a decrease in pretax book income partially offset by state income tax adjustments.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2013 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 243 for a discussion of accounting pronouncements.


130



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
  Three Months Ended Six Months Ended
  June 30, June 30,
  2014 2013 2014 2013
REVENUES        
Electric Generation, Transmission and Distribution $739,962
 $817,493
 $1,586,868
 $1,751,174
Sales to AEP Affiliates 44,443
 274,390
 76,421
 560,032
Other Revenues – Affiliated —
 7,583
 —
 15,423
Other Revenues – Nonaffiliated 1,756
 3,528
 3,064
 10,155
TOTAL REVENUES 786,161
 1,102,994
 1,666,353
 2,336,784
         
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation —
 352,368
 —
 761,952
Purchased Electricity for Resale 64,059
 37,158
 143,189
 80,343
Purchased Electricity from AEP Affiliates 267,631
 73,290
 581,755
 153,671
Amortization of Generation Deferrals 24,977
 —
 56,163
 —
Other Operation 131,485
 137,265
 282,911
 321,452
Maintenance 48,590
 72,997
 83,241
 147,292
Asset Impairments and Other Related Charges —
 154,304
 —
 154,304
Depreciation and Amortization 51,485
 102,346
 110,184
 194,670
Taxes Other Than Income Taxes 83,913
 100,194
 179,170
 205,215
TOTAL EXPENSES 672,140
 1,029,922
 1,436,613
 2,018,899
         
OPERATING INCOME 114,021
 73,072
 229,740
 317,885
         
Other Income (Expense):  
  
  
  
Interest Income 2,899
 2,326
 6,173
 2,689
Carrying Costs Income 6,874
 3,757
 13,988
 7,020
Allowance for Equity Funds Used During Construction 1,342
 521
 3,068
 1,825
Interest Expense (32,759) (47,244) (65,766) (97,417)
         
INCOME BEFORE INCOME TAX EXPENSE 92,377
 32,432
 187,203
 232,002
         
Income Tax Expense 35,842
 11,376
 69,894
 81,172
         
NET INCOME $56,535
 $21,056
 $117,309
 $150,830
The common stock of OPCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.


131


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
  Three Months Ended Six Months Ended
  June 30, June 30,
  2014 2013 2014 2013
Net Income $56,535
 $21,056
 $117,309
 $150,830
         
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES        
Cash Flow Hedges, Net of Tax of $185 and $293 for the Three Months Ended June 30, 2014 and 2013, Respectively, and $426 and $281 for the Six Months Ended June 30, 2014 and 2013, Respectively (343) (545) (791) 521
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,760 and $3,520 for the Three and Six Months Ended in 2013, Respectively —
 3,270
 —
 6,539
   
  
  
  
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) (343) 2,725
 (791) 7,060
         
TOTAL COMPREHENSIVE INCOME $56,192
 $23,781
 $116,518
 $157,890
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.


132


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
 Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
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
  
  
  
  
  
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2013$321,201
 $663,782
 $633,203
 $7,079
 $1,625,265
          
Common Stock Dividends 
  
 (35,000)  
 (35,000)
Net Income 
  
 117,309
  
 117,309
Other Comprehensive Loss 
  
  
 (791) (791)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2014$321,201
 $663,782
 $715,512
 $6,288
 $1,706,783
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.


133


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2014 and December 31, 2013
(in thousands)
(Unaudited)
  June 30, December 31,
  2014 2013
CURRENT ASSETS    
Cash and Cash Equivalents $4,475
 $3,004
Restricted Cash for Securitized Funding 43,003
 19,387
Advances to Affiliates —
 339,070
Accounts Receivable:    
Customers 58,336
 67,054
Affiliated Companies 65,704
 74,771
Accrued Unbilled Revenues 22,230
 36,353
Miscellaneous 607
 1,559
Allowance for Uncollectible Accounts (170) (34,984)
Total Accounts Receivable 146,707
 144,753
Notes Receivable Due Within One Year - Affiliated 125,130
 178,580
Materials and Supplies 57,916
 53,711
Risk Management Assets 9,299
 3,082
Deferred Income Tax Benefits 17,190
 36,105
Accrued Tax Benefits 5,164
 7,109
Prepayments and Other Current Assets 6,063
 22,312
TOTAL CURRENT ASSETS 414,947
 807,113
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Transmission 2,054,005
 2,011,289
Distribution 3,953,298
 3,877,532
Other Property, Plant and Equipment 384,803
 364,573
Construction Work in Progress 200,658
 185,428
Total Property, Plant and Equipment 6,592,764
 6,438,822
Accumulated Depreciation and Amortization 1,999,165
 1,973,042
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 4,593,599
 4,465,780
     
OTHER NONCURRENT ASSETS    
Notes Receivable - Affiliated 32,245
 118,245
Regulatory Assets 1,412,717
 1,378,697
Securitized Assets 121,613
 131,582
Deferred Charges and Other Noncurrent Assets 160,460
 260,141
TOTAL OTHER NONCURRENT ASSETS 1,727,035
 1,888,665
     
TOTAL ASSETS $6,735,581
 $7,161,558
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.


134


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2014 and December 31, 2013
(dollars in thousands)
(Unaudited)
  June 30, December 31,
  2014 2013
CURRENT LIABILITIES    
Advances from Affiliates $34,723
 $—
Accounts Payable:  
  
General 124,119
 146,307
Affiliated Companies 155,441
 222,889
Long-term Debt Due Within One Year - Nonaffiliated    
(June 30, 2014 and December 31, 2013 Amounts Include $57,137 and $34,936, Respectively, Related to Ohio Phase-in-Recovery Funding) 182,335
 438,595
Customer Deposits 49,620
 49,140
Accrued Taxes 276,729
 429,260
Accrued Interest 36,184
 40,853
Other Current Liabilities 93,008
 95,194
TOTAL CURRENT LIABILITIES 952,159
 1,422,238
     
NONCURRENT LIABILITIES    
Long-term Debt - Nonaffiliated    
(June 30, 2014 and December 31, 2013 Amounts Include $210,267 and $232,466, Respectively, Related to Ohio Phase-in-Recovery Funding) 2,188,617
 2,296,580
Deferred Income Taxes 1,362,794
 1,330,711
Regulatory Liabilities and Deferred Investment Tax Credits 477,139
 435,499
Employee Benefits and Pension Obligations 22,724
 28,329
Deferred Credits and Other Noncurrent Liabilities 25,365
 22,936
TOTAL NONCURRENT LIABILITIES 4,076,639
 4,114,055
     
TOTAL LIABILITIES 5,028,798
 5,536,293
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
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 663,782
 663,782
Retained Earnings 715,512
 633,203
Accumulated Other Comprehensive Income (Loss) 6,288
 7,079
TOTAL COMMON SHAREHOLDER’S EQUITY 1,706,783
 1,625,265
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $6,735,581
 $7,161,558
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.


135


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
  Six Months Ended June 30,
  2014 2013
OPERATING ACTIVITIES  
  
Net Income $117,309
 $150,830
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 110,184
 194,670
Amortization of Generation Deferrals 56,163
 —
Deferred Income Taxes 41,576
 55,839
Asset Impairments and Other Related Charges —
 154,304
Carrying Costs Income (13,988) (7,020)
Allowance for Equity Funds Used During Construction (3,068) (1,825)
Mark-to-Market of Risk Management Contracts (6,379) 9,448
Pension Contributions to Qualified Plan Trusts (6,547) —
Property Taxes 100,522
 111,392
Fuel Over/Under-Recovery, Net 28,671
 15,267
Deferral of Ohio Capacity Costs, Net (120,743) (102,240)
Change in Other Noncurrent Assets 13,281
 (16,273)
Change in Other Noncurrent Liabilities 46,213
 2,421
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net (2,256) 100,747
Fuel, Materials and Supplies (4,205) 9,714
Accounts Payable (70,228) (66,947)
Customer Deposits 480
 (2,302)
Accrued Taxes, Net (138,584) (168,818)
Other Current Assets (560) 5,391
Other Current Liabilities (24,522) (23,557)
Net Cash Flows from Operating Activities 123,319
 421,041
     
INVESTING ACTIVITIES  
  
Construction Expenditures (213,974) (296,888)
Change in Restricted Cash for Securitized Funding (23,616) —
Change in Advances to Affiliates, Net 339,070
 106,101
Proceeds from Notes Receivable - Affiliated 139,450
 —
Other Investing Activities 3,570
 11,960
Net Cash Flows from (Used for) Investing Activities 244,500
 (178,827)
     
FINANCING ACTIVITIES  
  
Issuance of Long-term Debt – Nonaffiliated —
 49,562
Issuance of Long-term Debt – Affiliated —
 200,000
Change in Advances from Affiliates, Net 34,723
 292,051
Retirement of Long-term Debt – Nonaffiliated (364,498) (606,000)
Principal Payments for Capital Lease Obligations (2,562) (4,747)
Dividends Paid on Common Stock (35,000) (175,000)
Other Financing Activities 989
 825
Net Cash Flows Used for Financing Activities (366,348) (243,309)
     
Net Increase (Decrease) in Cash and Cash Equivalents 1,471
 (1,095)
Cash and Cash Equivalents at Beginning of Period 3,004
 3,640
Cash and Cash Equivalents at End of Period $4,475
 $2,545
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $69,127
 $105,876
Net Cash Paid for Income Taxes 10,863
 48,841
Noncash Acquisitions Under Capital Leases 3,754
 3,335
Construction Expenditures Included in Current Liabilities as of June 30, 40,878
 56,618
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.


136



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

The condensed notes to OPCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to OPCo.
Page
Number
Significant Accounting Matters
165
New Accounting Pronouncements
166
Comprehensive Income
167
Rate Matters
186
Commitments, Guarantees and Contingencies
196
Disposition and Impairment
200
Benefit Plans
201
Business Segments
204
Derivatives and Hedging
205
Fair Value Measurements
219
Income Taxes
233
Financing Activities
234
Variable Interest Entities
238




137




PUBLIC SERVICE COMPANY OF OKLAHOMA

138



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

EXECUTIVE OVERVIEW

Regulatory Activity

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years.

In June 2014, a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors was filed with the OCC. The parties to the stipulation recommended no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider would provide $7 million of revenues in 2014 and increases to $27 million in 2016. New depreciation rates are recommended for advanced metering investments and existing meters, to be effective November 2014. Additionally, the stipulation recommends recovery of regulatory assets for 2013 storms and regulatory case expenses. In July 2014, the Attorney General joined in the stipulation agreement. A hearing at the OCC was held in July 2014. If the OCC were to disallow any portion of this settlement agreement, it could reduce future net income and cash flows and impact financial condition. See the “2014 Oklahoma Base Rate Case” section of PSO Rate Matters in Note 4.

SPP Integrated Power Market

In March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In the past, PSO and SWEPCo would satisfy their load requirements with their own generation resources or through the Operating Agreement. In the new integrated power market, PSO and SWEPCo operate as standalone entities by offering their respective generation into the SPP power market, which then economically dispatches the resources. This change further enables retail customers to obtain low cost power through either internal generation or power purchases from the SPP market. The new integrated power market now operates in a similar manner as the PJM power market for the AEP East Companies. No significant impact on results of operations is expected due to this change.

Litigation and Environmental Issues

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 164. 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 243 for additional discussion of relevant factors.


139


RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in millions of KWhs)
Retail: 
  
  
  
Residential1,363
 1,370
 2,997
 2,806
Commercial1,311
 1,275
 2,450
 2,354
Industrial1,339
 1,291
 2,532
 2,485
Miscellaneous322
 321
 600
 598
Total Retail4,335
 4,257
 8,579
 8,243
        
Wholesale49
 267
 276
 522
        
Total KWhs4,384
 4,524
 8,855
 8,765

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.

Summary of Heating and Cooling Degree Days
 Three Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in degree days)
Actual - Heating (a)48
 119
 1,417
 1,208
Normal - Heating (b)40
 37
 1,085
 1,082
        
Actual - Cooling (c)673
 644
 676
 649
Normal - Cooling (b)649
 649
 664
 664

(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.

140



Second Quarter of 2014 Compared to Second Quarter of 2013
Reconciliation of Second Quarter of 2013 to Second Quarter of 2014
Net Income
(in millions)
   
Second Quarter of 2013 $28
   
Changes in Expenses and Other:  
Other Operation and Maintenance (14)
Depreciation and Amortization (1)
Taxes Other Than Income Taxes 5
Other Income (1)
Total Change in Expenses and Other (11)
   
Income Tax Expense 5
   
Second Quarter of 2014 $22

There were no material changes in the major components of Gross Margin in the second quarter of 2014. Retail margins include rate riders which have corresponding offsets in other expense items below.

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 generation plant operation and maintenance expenses.
A $5 million increase in transmission expenses primarily due to increased SPP transmission services.
A $2 million increase in energy efficiency program expenses.
These increases were partially offset by:
A $3 million decrease in distribution expenses primarily related to the amortization of the 2007 and 2010 storm deferrals which were fully recovered in 2013.
Taxes Other Than Income Taxes decreased $5 million primarily due to a June 2014 property tax adjustment resulting from a change in Oklahoma tax law.
Income Tax Expense decreased $5 million primarily due to a decrease in pretax book income.

141



Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013
Reconciliation of Six Months Ended June 30, 2013 to Six Months Ended June 30, 2014
Net Income
(in millions)
   
Six Months Ended June 30, 2013 $42
   
Changes in Gross Margin:  
Transmission Revenues 1
Other Revenues (1)
Total Change in Gross Margin —
   
Changes in Expenses and Other:  
Other Operation and Maintenance (21)
Taxes Other Than Income Taxes 3
Other Income (1)
Total Change in Expenses and Other (19)
   
Income Tax Expense 8
   
Six Months Ended June 30, 2014 $31

There were no material changes in the major components of Gross Margin in the first six months of 2014. Retail margins include rate riders which have corresponding offsets in other expense items below.

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

Other Operation and Maintenance expenses increased $21 million primarily due to the following:
A $12 million increase in transmission expenses primarily due to increased SPP transmission services.
A $10 million increase in generation plant operation and maintenance expenses.
A $2 million increase in energy efficiency program expenses.
These increases were partially offset by:
A $6 million decrease in distribution expenses primarily related to amortization of the 2007 and 2010 storm deferrals which were fully recovered in 2013.
Taxes Other Than Income Taxes decreased $3 million primarily due to a June 2014 property tax adjustment resulting from a change in Oklahoma tax law.
Income Tax Expense decreased $8 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 2013 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 243 for a discussion of accounting pronouncements.


142



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
  Three Months Ended Six Months Ended
  June 30, June 30,
  2014 2013 2014 2013
REVENUES        
Electric Generation, Transmission and Distribution $316,524
 $317,302
 $613,234
 $577,205
Sales to AEP Affiliates 854
 5,693
 5,451
 7,527
Other Revenues 1,437
 1,692
 1,515
 2,244
TOTAL REVENUES 318,815
 324,687
 620,200
 586,976
         
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 41,612
 86,241
 107,549
 129,551
Purchased Electricity for Resale 104,604
 58,835
 184,295
 123,490
Purchased Electricity from AEP Affiliates —
 6,823
 11,024
 17,039
Other Operation 62,785
 53,659
 121,496
 101,466
Maintenance 29,678
 24,753
 54,423
 53,325
Depreciation and Amortization 24,607
 24,078
 48,589
 48,258
Taxes Other Than Income Taxes 6,651
 11,827
 18,620
 21,824
TOTAL EXPENSES 269,937
 266,216
 545,996
 494,953
         
OPERATING INCOME 48,878
 58,471
 74,204
 92,023
         
Other Income (Expense):  
  
  
  
Interest Income 4
 193
 1
 1,121
Carrying Costs Income —
 110
 —
 317
Allowance for Equity Funds Used During Construction 590
 844
 2,021
 1,824
Interest Expense (13,779) (13,259) (27,096) (26,599)
         
INCOME BEFORE INCOME TAX EXPENSE 35,693
 46,359
 49,130
 68,686
         
Income Tax Expense 13,244
 17,927
 18,233
 26,561
         
NET INCOME $22,449
 $28,432
 $30,897
 $42,125
The common stock of PSO is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

143


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
  Three Months Ended Six Months Ended
  June 30, June 30,
  2014 2013 2014 2013
Net Income $22,449
 $28,432
 $30,897
 $42,125
         
OTHER COMPREHENSIVE LOSS, NET OF TAXES  
  
  
  
Cash Flow Hedges, Net of Tax of $103 and $137 for the Three Months Ended June 30, 2014 and 2013, Respectively, and $235 and $227 for the Six Months Ended June 30, 2014 and 2013, Respectively (190) (254) (436) (421)
   
  
  
  
TOTAL COMPREHENSIVE INCOME $22,259
 $28,178
 $30,461
 $41,704
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

144


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
  Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
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
  
  
  
  
  
TOTAL COMMON SHAREHOLDER'S         
 EQUITY - DECEMBER 31, 2013$157,230
 $364,037
 $415,076
 $5,758
 $942,101
          
Net Income 
  
 30,897
  
 30,897
Other Comprehensive Loss 
  
  
 (436) (436)
TOTAL COMMON SHAREHOLDER'S         
 EQUITY - JUNE 30, 2014$157,230
 $364,037
 $445,973
 $5,322
 $972,562
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.


145


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
June 30, 2014 and December 31, 2013
(in thousands)
(Unaudited)
  June 30, December 31,
  2014 2013
CURRENT ASSETS    
Cash and Cash Equivalents $1,627
 $1,277
Accounts Receivable:    
Customers 42,342
 32,314
Affiliated Companies 23,901
 30,392
Miscellaneous 3,763
 3,102
Allowance for Uncollectible Accounts (278) (462)
Total Accounts Receivable 69,728
 65,346
Fuel 11,742
 15,191
Materials and Supplies 52,826
 52,707
Risk Management Assets 522
 1,167
Deferred Income Tax Benefits —
 7,333
Accrued Tax Benefits 34,491
 21,665
Regulatory Asset for Under-Recovered Fuel Costs 41,852
 3,298
Prepayments and Other Current Assets 6,886
 6,194
TOTAL CURRENT ASSETS 219,674
 174,178
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 1,243,810
 1,203,221
Transmission 768,291
 731,312
Distribution 2,032,961
 1,986,032
Other Property, Plant and Equipment (Including Plant to be Retired) 417,407
 393,026
Construction Work in Progress 129,655
 175,890
Total Property, Plant and Equipment 4,592,124
 4,489,481
Accumulated Depreciation and Amortization 1,318,667
 1,323,522
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 3,273,457
 3,165,959
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 162,026
 156,690
Employee Benefits and Pension Assets 27,436
 22,629
Deferred Charges and Other Noncurrent Assets 22,596
 7,238
TOTAL OTHER NONCURRENT ASSETS 212,058
 186,557
     
TOTAL ASSETS $3,705,189
 $3,526,694
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

146


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2014 and December 31, 2013
(Unaudited)
  June 30, December 31,
  2014 2013
  (in thousands)
CURRENT LIABILITIES    
Advances from Affiliates $124,800
 $36,772
Accounts Payable:  
  
General 115,000
 150,184
Affiliated Companies 60,888
 45,427
Long-term Debt Due Within One Year – Nonaffiliated 421
 34,115
Risk Management Liabilities 102
 85
Customer Deposits 47,789
 45,379
Accrued Taxes 34,607
 23,442
Accrued Interest 12,226
 12,646
Other Current Liabilities 50,868
 58,992
TOTAL CURRENT LIABILITIES 446,701
 407,042
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 1,040,654
 965,695
Deferred Income Taxes 852,598
 836,556
Regulatory Liabilities and Deferred Investment Tax Credits 326,133
 327,673
Employee Benefits and Pension Obligations 10,633
 10,561
Deferred Credits and Other Noncurrent Liabilities 55,908
 37,066
TOTAL NONCURRENT LIABILITIES 2,285,926
 2,177,551
     
TOTAL LIABILITIES 2,732,627
 2,584,593
     
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
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 445,973
 415,076
Accumulated Other Comprehensive Income (Loss) 5,322
 5,758
TOTAL COMMON SHAREHOLDER’S EQUITY 972,562
 942,101
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $3,705,189
 $3,526,694
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

147


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
  Six Months Ended June 30,
  2014 2013
OPERATING ACTIVITIES  
  
Net Income $30,897
 $42,125
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 48,589
 48,258
Deferred Income Taxes 28,493
 27,562
Allowance for Equity Funds Used During Construction (2,021) (1,824)
Mark-to-Market of Risk Management Contracts 578
 (3,779)
Pension Contributions to Qualified Plan Trust (4,439) —
Property Taxes (15,940) (20,353)
Fuel Over/Under-Recovery, Net (38,554) (19,331)
Change in Other Noncurrent Assets (10,411) 10,999
Change in Other Noncurrent Liabilities (3,079) (10,740)
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net (4,382) (4,747)
Fuel, Materials and Supplies 3,330
 (1,099)
Accounts Payable 959
 21,581
Accrued Taxes, Net (1,116) 13,052
Other Current Assets (1,386) 1,940
Other Current Liabilities 9,888
 (7,298)
Net Cash Flows from Operating Activities 41,406
 96,346
     
INVESTING ACTIVITIES  
  
Construction Expenditures (170,565) (112,864)
Change in Advances to Affiliates, Net —
 10,558
Other Investing Activities 1,560
 9,090
Net Cash Flows Used for Investing Activities (169,005) (93,216)
     
FINANCING ACTIVITIES  
  
Issuance of Long-term Debt – Nonaffiliated 74,975
 —
Change in Advances from Affiliates, Net 88,028
 25,276
Retirement of Long-term Debt – Nonaffiliated (33,906) (200)
Principal Payments for Capital Lease Obligations (1,731) (1,586)
Dividends Paid on Common Stock —
 (27,500)
Other Financing Activities 583
 555
Net Cash Flows from (Used for) Financing Activities 127,949
 (3,455)
     
Net Increase (Decrease) in Cash and Cash Equivalents 350
 (325)
Cash and Cash Equivalents at Beginning of Period 1,277
 1,367
Cash and Cash Equivalents at End of Period $1,627
 $1,042
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $26,684
 $26,155
Net Cash Paid for Income Taxes 2,463
 6,295
Noncash Acquisitions Under Capital Leases 1,190
 5,594
Construction Expenditures Included in Current Liabilities as of June 30, 40,150
 26,812
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

148


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
165
New Accounting Pronouncements
166
Comprehensive Income
167
Rate Matters
186
Commitments, Guarantees and Contingencies
196
Benefit Plans
201
Business Segments
204
Derivatives and Hedging
205
Fair Value Measurements
219
Income Taxes
233
Financing Activities
234
Variable Interest Entities
238

149




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED


150


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

EXECUTIVE OVERVIEW

Regulatory Activity

2012 Texas Base Rate Case

Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap.  As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances.  The resulting annual base rate increase is approximately $52 million.  In May 2014, intervenors filed appeals of the order with the Texas District Court.  In June 2014, SWEPCo intervened in those appeals and filed initial responses.  If any part of the PUCT order is overturned it could reduce future net income and cash flows and impact financial condition.  See the “2012 Texas Base Rate Case” section of SWEPCo Rate Matters in Note 4.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant. In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013. The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. 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 SWEPCo Rate Matters in Note 4.

2014 Louisiana Formula Rate Filing

In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC.  The filing included a $5 million annual increase to be effective August 2014.  SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchase power agreement attributable to Louisiana customers.  These increases are subject to LPSC staff review.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC.  Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC.  As of June 30, 2014, SWEPCo has incurred $72 million in costs related to these projects.  SWEPCo will seek to recover these project costs from customers through filings at the state commissions and FERC. These environmental projects could be impacted by pending carbon emission regulations.  See "CO2 Regulation"  section of “Environmental Issues” within “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries”.  As of June 30, 2014, the net book value of Welsh Plant, Units 1 and 3 was $297 million, before cost of removal, including materials and supplies inventory and CWIP.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 


151



SPP Integrated Power Market

In March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In the past, PSO and SWEPCo would satisfy their load requirements with their own generation resources or through the Operating Agreement. In the new integrated power market, PSO and SWEPCo operate as standalone entities by offering their respective generation into the SPP power market, which then economically dispatches the resources. This change further enables retail customers to obtain low cost power through either internal generation or power purchases from the SPP market. The new integrated power market now operates in a similar manner as the PJM power market for the AEP East Companies. No significant impact on results of operations is expected due to this change.

Litigation and Environmental Issues

In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 164. 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 243 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,
 2014 2013 2014 2013
 (in millions of KWhs)
Retail: 
  
  
  
Residential1,278
 1,446
 3,025
 2,940
Commercial1,446
 1,556
 2,839
 2,835
Industrial1,565
 1,465
 2,942
 2,724
Miscellaneous20
 22
 40
 41
Total Retail4,309
 4,489
 8,846
 8,540
        
Wholesale2,285
 2,131
 4,564
 4,574
        
Total KWhs6,594
 6,620
 13,410
 13,114


152


Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.

Summary of Heating and Cooling Degree Days
 Three Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in degree days)
Actual - Heating (a)45
 68
 1,039
 800
Normal - Heating (b)26
 25
 747
 753
        
Actual - Cooling (c)675
 703
 685
 719
Normal - Cooling (b)725
 725
 758
 758

(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.


153


Second Quarter of 2014 Compared to Second Quarter of 2013
Reconciliation of Second Quarter of 2013 to Second Quarter of 2014
Net Income
(in millions)
   
Second Quarter of 2013 $30
   
Changes in Gross Margin:  
Retail Margins (a) 12
Off-system Sales 3
Transmission Revenues (3)
Other Revenues 1
Total Change in Gross Margin 13
   
Changes in Expenses and Other:  
Other Operation and Maintenance (10)
Taxes Other Than Income Taxes (1)
Allowance for Equity Funds Used During Construction 1
Interest Expense 2
Total Change in Expenses and Other (8)
   
Income Tax Expense (2)
   
Second Quarter of 2014 $33

(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 $12 million primarily due to the following:
An $11 million increase in municipal and cooperative revenues due to formula rate adjustments.
A $9 million increase primarily due to the Texas rate order related to the Turk Plant.
A $4 million increase due to fuel cost adjustments.
These increases were partially offset by:
A $10 million decrease primarily due to lower weather-normalized retail sales.
A $3 million decrease in weather-related usage primarily due to a 4% decrease in cooling degree days.
Margins from Off-system Sales increased $3 million primarily due to increased market prices and higher physical sales margins.
Transmission Revenues decreased $3 million primarily due to lower SPP margins.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $10 million primarily due to the following:
A $6 million increase in transmission expenses primarily due to increased SPP transmission services.
A $1 million increase in energy efficiency program expenses.

154


Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013
Reconciliation of Six Months Ended June 30, 2013 to Six Months Ended June 30, 2014
Net Income
(in Millions)
   
Six Months Ended June 30, 2013 $42
   
Changes in Gross Margin:  
Retail Margins (a) 36
Off-system Sales 5
Transmission Revenues (2)
Other Revenues 1
Total Change in Gross Margin 40
   
Changes in Expenses and Other:  
Other Operation and Maintenance (22)
Depreciation and Amortization (1)
Taxes Other Than Income Taxes (2)
Allowance for Equity Funds Used During Construction 2
Interest Expense 4
Total Change in Expenses and Other (19)
   
Income Tax Expense (7)
   
Six Months Ended June 30, 2014 $56

(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 $36 million primarily due to the following:
A $30 million increase due to the Texas and Louisiana rate orders related to the Turk Plant.
A $14 million increase in municipal and cooperative revenues due to formula rate adjustments.
A $4 million net increase in weather-related usage primarily due to a 30% increase in heating degree days, partially offset by a decrease in cooling degree days.
These increases were partially offset by:
A $12 million decrease primarily due to lower weather-normalized retail sales.
Margins from Off-system Sales increased $5 million primarily due to increased market prices and higher physical sales margins.
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 $12 million increase in transmission expenses primarily due to increased SPP transmission services.
A $4 million increase in generation plant operation and maintenance expenses.
A $2 million increase in energy efficiency program expenses.
Interest Expense decreased $4 million primarily due to rate approvals in Louisiana and Texas and an increase in the debt component of AFUDC due to increased transmission and environmental projects.
Income Tax Expense increased $7 million primarily due to an increase in pretax book income.


155


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 2013 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 243 for a discussion of accounting pronouncements.

156



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
  Three Months Ended Six Months Ended
  June 30, June 30,
  2014 2013 2014 2013
REVENUES        
Electric Generation, Transmission and Distribution $444,652
 $408,852
 $871,279
 $790,129
Sales to AEP Affiliates 3,947
 10,930
 17,545
 23,639
Other Revenues 684
 391
 1,049
 722
TOTAL REVENUES 449,283
 420,173
 889,873
 814,490
         
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 161,116
 137,065
 306,703
 288,423
Purchased Electricity for Resale 40,255
 43,008
 101,420
 82,768
Purchased Electricity from AEP Affiliates —
 4,925
 3,766
 5,942
Other Operation 69,304
 60,795
 137,841
 120,243
Maintenance 33,668
 32,280
 64,079
 60,071
Depreciation and Amortization 45,864
 45,732
 91,525
 90,614
Taxes Other Than Income Taxes 20,289
 19,336
 41,026
 38,758
TOTAL EXPENSES 370,496
 343,141
 746,360
 686,819
         
OPERATING INCOME 78,787
 77,032
 143,513
 127,671
         
Other Income (Expense):  
  
  
  
Interest Income 206
 169
 92
 199
Allowance for Equity Funds Used During Construction 2,197
 1,368
 4,278
 2,392
Interest Expense (31,738) (33,547) (63,614) (67,537)
         
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS 49,452
 45,022
 84,269
 62,725
         
Income Tax Expense 17,045
 15,326
 29,210
 22,122
Equity Earnings of Unconsolidated Subsidiary 416
 531
 726
 1,172
         
NET INCOME 32,823
 30,227
 55,785
 41,775
         
Net Income Attributable to Noncontrolling Interest 1,126
 1,056
 2,228
 2,146
         
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $31,697
 $29,171
 $53,557
 $39,629
The common stock of SWEPCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

157


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
 Three Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
Net Income$32,823
 $30,227
 $55,785
 $41,775
        
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES 
  
  
  
Cash Flow Hedges, Net of Tax of $306 and $264 for the Three Months Ended June 30, 2014 and 2013, Respectively, and $576 and $585 for the Six Months Ended June 30, 2014 and 2013, Respectively567
 490
 1,069
 1,086
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $127 and $34 for the Three Months Ended June 30, 2014 and 2013, Respectively, and $253 and $68 for the Six Months Ended June 30, 2014 and 2013, Respectively(235) (64) (469) (127)
        
TOTAL OTHER COMPREHENSIVE INCOME332
 426
 600
 959
        
TOTAL COMPREHENSIVE INCOME33,155
 30,653
 56,385
 42,734
        
Total Comprehensive Income Attributable to Noncontrolling Interest1,126
 1,056
 2,228
 2,146
  
  
  
  
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$32,029
 $29,597
 $54,157
 $40,588
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

158


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
   SWEPCo Common Shareholder    
 Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 
Noncontrolling
Interest
 Total
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
            
TOTAL EQUITY - DECEMBER 31, 2013$135,660
 $674,606
 $1,253,617
 $(8,444) $478
 $2,055,917
            
Common Stock Dividends 
  
 (50,000)  
  
 (50,000)
Common Stock Dividends – Nonaffiliated 
  
  
  
 (2,309) (2,309)
Net Income 
  
 53,557
  
 2,228
 55,785
Other Comprehensive Income 
  
  
 600
  
 600
TOTAL EQUITY - JUNE 30, 2014$135,660
 $674,606
 $1,257,174
 $(7,844) $397
 $2,059,993
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

159


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2014 and December 31, 2013
(in thousands)
(Unaudited)
  June 30, December 31,
  2014 2013
CURRENT ASSETS    
Cash and Cash Equivalents
(June 30, 2014 and December 31, 2013 Amounts Include $14,629 and
$15,827, Respectively, Related to Sabine)
 $16,971
 $17,241
Accounts Receivable:    
Customers 70,873
 86,263
Affiliated Companies 18,641
 22,389
Miscellaneous 24,022
 27,175
Allowance for Uncollectible Accounts (321) (1,418)
Total Accounts Receivable 113,215
 134,409
Fuel
(June 30, 2014 and December 31, 2013 Amounts Include $33,143 and
$37,518, Respectively, Related to Sabine)
 98,076
 122,026
Materials and Supplies 75,898
 74,862
Risk Management Assets 506
 1,179
Deferred Income Tax Benefits 4,841
 177,297
Accrued Tax Benefits 139,864
 158
Regulatory Asset for Under-Recovered Fuel Costs 29,499
 17,949
Prepayments and Other Current Assets 21,677
 20,931
TOTAL CURRENT ASSETS 500,547
 566,052
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 3,790,118
 3,764,429
Transmission 1,242,567
 1,165,167
Distribution 1,872,030
 1,843,912
Other Property, Plant and Equipment (Including Plant to be Retired)
(June 30, 2014 and December 31, 2013 Amounts Include $295,442 and
$291,556, Respectively, Related to Sabine)
 881,351
 869,230
Construction Work in Progress 342,719
 281,849
Total Property, Plant and Equipment 8,128,785
 7,924,587
Accumulated Depreciation and Amortization
(June 30, 2014 and December 31, 2013 Amounts Include $142,707 and
$134,282, Respectively, Related to Sabine)
 2,456,059
 2,391,652
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 5,672,726
 5,532,935
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 365,527
 369,905
Deferred Charges and Other Noncurrent Assets 123,220
 92,890
TOTAL OTHER NONCURRENT ASSETS 488,747
 462,795
     
TOTAL ASSETS $6,662,020
 $6,561,782
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

160


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2014 and December 31, 2013
(Unaudited)
  June 30, December 31,
  2014 2013
  (in thousands)
CURRENT LIABILITIES    
Advances from Affiliates $79,098
 $9,180
Accounts Payable:    
General 145,830
 152,653
Affiliated Companies 73,442
 56,923
Long-term Debt Due Within One Year – Nonaffiliated 156,750
 3,250
Risk Management Liabilities 17
 —
Customer Deposits 58,445
 56,375
Accrued Taxes 71,928
 41,508
Accrued Interest 43,291
 43,996
Obligations Under Capital Leases 18,263
 17,899
Regulatory Liability for Over-Recovered Fuel Costs —
 7,275
Other Current Liabilities 68,460
 79,622
TOTAL CURRENT LIABILITIES 715,524
 468,681
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 1,885,135
 2,040,082
Deferred Income Taxes 1,281,275
 1,271,478
Regulatory Liabilities and Deferred Investment Tax Credits 471,225
 472,128
Asset Retirement Obligations 89,701
 87,630
Employee Benefits and Pension Obligations 14,157
 14,602
Obligations Under Capital Leases 98,823
 105,086
Deferred Credits and Other Noncurrent Liabilities 46,187
 46,178
TOTAL NONCURRENT LIABILITIES 3,886,503
 4,037,184
     
TOTAL LIABILITIES 4,602,027
 4,505,865
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
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 1,257,174
 1,253,617
Accumulated Other Comprehensive Income (Loss) (7,844) (8,444)
TOTAL COMMON SHAREHOLDER’S EQUITY 2,059,596
 2,055,439
     
Noncontrolling Interest 397
 478
     
TOTAL EQUITY 2,059,993
 2,055,917
     
TOTAL LIABILITIES AND EQUITY $6,662,020
 $6,561,782
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

161


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2014 and 2013
(in thousands)
(Unaudited)
  Six Months Ended June 30,
  2014 2013
OPERATING ACTIVITIES  
  
Net Income $55,785
 $41,775
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
Depreciation and Amortization 91,525
 90,614
Deferred Income Taxes 179,336
 39,624
Allowance for Equity Funds Used During Construction (4,278) (2,392)
Mark-to-Market of Risk Management Contracts 593
 35
Pension Contributions to Qualified Plan Trust (3,832) —
Property Taxes (25,053) (23,607)
Fuel Over/Under-Recovery, Net (18,825) (17,350)
Change in Other Noncurrent Assets 8,034
 (3,639)
Change in Other Noncurrent Liabilities (3,464) 5,647
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net 21,194
 6,979
Fuel, Materials and Supplies 22,914
 (6,452)
Accounts Payable 8,186
 1,277
Accrued Taxes, Net (108,460) 11,079
Other Current Assets (3,310) 3,541
Other Current Liabilities (10,700) (12,121)
Net Cash Flows from Operating Activities 209,645
 135,010
     
INVESTING ACTIVITIES    
Construction Expenditures (220,968) (187,607)
Change in Advances to Affiliates, Net —
 139,023
Other Investing Activities 3,394
 342
Net Cash Flows Used for Investing Activities (217,574) (48,242)
     
FINANCING ACTIVITIES    
Credit Facility Borrowings —
 17,091
Change in Advances from Affiliates, Net 69,918
 —
Retirement of Long-term Debt – Nonaffiliated (1,625) (1,625)
Credit Facility Repayments —
 (19,694)
Principal Payments for Capital Lease Obligations (9,156) (8,877)
Dividends Paid on Common Stock (50,000) (62,500)
Dividends Paid on Common Stock – Nonaffiliated (2,309) (2,040)
Other Financing Activities 831
 681
Net Cash Flows from (Used for) Financing Activities 7,659
 (76,964)
     
Net Increase (Decrease) in Cash and Cash Equivalents (270) 9,804
Cash and Cash Equivalents at Beginning of Period 17,241
 2,036
Cash and Cash Equivalents at End of Period $16,971
 $11,840
     
SUPPLEMENTARY INFORMATION    
Cash Paid for Interest, Net of Capitalized Amounts $60,001
 $61,663
Net Cash Paid (Received) for Income Taxes (7,556) 1,161
Noncash Acquisitions Under Capital Leases 3,354
 2,851
Construction Expenditures Included in Current Liabilities as of June 30, 63,813
 35,940
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 164.

162


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
165
New Accounting Pronouncements
166
Comprehensive Income
167
Rate Matters
186
Commitments, Guarantees and Contingencies
196
Benefit Plans
201
Business Segments
204
Derivatives and Hedging
205
Fair Value Measurements
219
Income Taxes
233
Financing Activities
234
Variable Interest Entities
238





163


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 MattersAPCo, I&M, OPCo, PSO, SWEPCo
165
New Accounting PronouncementsAPCo, I&M, OPCo, PSO, SWEPCo
166
Comprehensive IncomeAPCo, I&M, OPCo, PSO, SWEPCo
167
Rate MattersAPCo, I&M, OPCo, PSO, SWEPCo
186
Commitments, Guarantees and ContingenciesAPCo, I&M, OPCo, PSO, SWEPCo
196
Disposition and ImpairmentOPCo
200
Benefit PlansAPCo, I&M, OPCo, PSO, SWEPCo
201
Business SegmentsAPCo, I&M, OPCo, PSO, SWEPCo
204
Derivatives and HedgingAPCo, I&M, OPCo, PSO, SWEPCo
205
Fair Value MeasurementsAPCo, I&M, OPCo, PSO, SWEPCo
219
Income TaxesAPCo, I&M, OPCo, PSO, SWEPCo
233
Financing ActivitiesAPCo, I&M, OPCo, PSO, SWEPCo
234
Variable Interest EntitiesAPCo, I&M, OPCo, PSO, SWEPCo
238


164


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, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 25, 2014.

Revenue Recognition

Electricity Supply and Delivery Activities - Transactions with PJM

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrant Subsidiaries recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.

APCo and I&M sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary’s retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenues on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement in 2014, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices.

SPP Integrated Power Market

In March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In the past, PSO and SWEPCo would satisfy their load requirements with their own generation resources or through the Operating Agreement. In the new integrated power market, PSO and SWEPCo operate as standalone entities by offering their respective generation into the SPP power market, which then economically dispatches the resources. This change further enables retail customers to obtain low cost power through either internal generation or power purchases from the SPP market. The new integrated power market now operates in a similar manner as the PJM power market for the AEP East Companies. No significant impact on results of operations is expected due to this change.


165


2. NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following final pronouncements will impact the financial statements.

ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08)

In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management plans to adopt ASU 2014-08 effective January 1, 2015.

ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09)

In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. This standard must be retrospectively applied to all reporting periods presented in financial reports issued after the effective date.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016. Early adoption is not permitted. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2017.



166


3.  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, 2014 and 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, 2014
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 Total
  (in thousands)
Balance in AOCI as of March 31, 2014 $87
 $3,343
 $(566) $2,864
Change in Fair Value Recognized in AOCI 103
 —
 —
 103
Amounts Reclassified from AOCI (190) 253
 (333) (270)
Net Current Period Other
Comprehensive Income
 (87) 253
 (333) (167)
Balance in AOCI as of June 30, 2014 $—
 $3,596
 $(899) $2,697

APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2013
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
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)


167


APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2014
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 Total
  (in thousands)
Balance in AOCI as of December 31, 2013 $94
 $3,090
 $(233) $2,951
Change in Fair Value Recognized in AOCI 1,686
 —
 —
 1,686
Amounts Reclassified from AOCI (1,780) 506
 (666) (1,940)
Net Current Period Other
Comprehensive Income
 (94) 506
 (666) (254)
Balance in AOCI as of June 30, 2014 $—
 $3,596
 $(899) $2,697

APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2013
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
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)


168


I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2014
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 Total
  (in thousands)
Balance in AOCI as of March 31, 2014 $61
 $(15,566) $464
 $(15,041)
Change in Fair Value Recognized in AOCI 68
 —
 —
 68
Amounts Reclassified from AOCI (129) 411
 43
 325
Net Current Period Other
Comprehensive Income
 (61) 411
 43
 393
Balance in AOCI as of June 30, 2014 $—
 $(15,155) $507
 $(14,648)

I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2013
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
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)


169


I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2014
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 Total
  (in thousands)
Balance in AOCI as of December 31, 2013 $46
 $(15,976) $421
 $(15,509)
Change in Fair Value Recognized in AOCI 1,130
 —
 —
 1,130
Amounts Reclassified from AOCI (1,176) 821
 86
 (269)
Net Current Period Other
Comprehensive Income
 (46) 821
 86
 861
Balance in AOCI as of June 30, 2014 $—
 $(15,155) $507
 $(14,648)

I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2013
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
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)


170


OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2014
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 Total
  (in thousands)
Balance in AOCI as of March 31, 2014 $—
 $6,631
 $—
 $6,631
Change in Fair Value Recognized in AOCI —
 —
 —
 —
Amounts Reclassified from AOCI —
 (343) —
 (343)
Net Current Period Other
Comprehensive Income
 —
 (343) —
 (343)
Balance in AOCI as of June 30, 2014 $—
 $6,288
 $—
 $6,288
OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2013
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
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)


171


OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2014
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 Total
  (in thousands)
Balance in AOCI as of December 31, 2013 $105
 $6,974
 $—
 $7,079
Change in Fair Value Recognized in AOCI —
 —
 —
 —
Amounts Reclassified from AOCI (105) (686) —
 (791)
Net Current Period Other
Comprehensive Income
 (105) (686) —
 (791)
Balance in AOCI as of June 30, 2014 $—
 $6,288
 $—
 $6,288

OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2013
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
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)


172


PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2014
  Cash Flow Hedges  
  Commodity 
Interest Rate and
Foreign Currency
 Total
  (in thousands)
Balance in AOCI as of March 31, 2014 $—
 $5,512
 $5,512
Change in Fair Value Recognized in AOCI —
 —
 —
Amounts Reclassified from AOCI —
 (190) (190)
Net Current Period Other Comprehensive Income —
 (190) (190)
Balance in AOCI as of June 30, 2014 $—
 $5,322
 $5,322
PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2013
  Cash Flow Hedges  
  Commodity 
Interest Rate and
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


173


PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2014
  Cash Flow Hedges  
  Commodity 
Interest Rate and
Foreign Currency
 Total
  (in thousands)
Balance in AOCI as of December 31, 2013 $57
 $5,701
 $5,758
Change in Fair Value Recognized in AOCI —
 —
 —
Amounts Reclassified from AOCI (57) (379) (436)
Net Current Period Other Comprehensive Income (57) (379) (436)
Balance in AOCI as of June 30, 2014 $—
 $5,322
 $5,322

PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2013
  Cash Flow Hedges  
  Commodity 
Interest Rate and
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


174


SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2014
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 Total
  (in thousands)
Balance in AOCI as of March 31, 2014 $—
 $(12,736) $4,560
 $(8,176)
Change in Fair Value Recognized in AOCI —
 —
 —
 —
Amounts Reclassified from AOCI —
 567
 (235) 332
Net Current Period Other
Comprehensive Income
 —
 567
 (235) 332
Balance in AOCI as of June 30, 2014 $—
 $(12,169) $4,325
 $(7,844)

SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2013
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
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)


175


SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2014
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 Total
  (in thousands)
Balance in AOCI as of December 31, 2013 $66
 $(13,304) $4,794
 $(8,444)
Change in Fair Value Recognized in AOCI —
 —
 —
 —
Amounts Reclassified from AOCI (66) 1,135
 (469) 600
Net Current Period Other
Comprehensive Income
 (66) 1,135
 (469) 600
Balance in AOCI as of June 30, 2014 $—
 $(12,169) $4,325
 $(7,844)

SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2013
  Cash Flow Hedges    
  Commodity 
Interest Rate and
Foreign Currency
 
Pension
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)


176


Reclassifications from Accumulated Other Comprehensive Income

The following tables provide details of reclassifications from AOCI for the three and six months ended June 30, 2014 and 2013.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs.  See Note 7 for additional details.
APCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended June 30, 2014 and 2013
  
Amount of (Gain) Loss
Reclassified from AOCI
  Three Months Ended June 30,
  2014 2013
Gains and Losses on Cash Flow Hedges (in thousands)
Commodity:  
  
Electric Generation, Transmission and Distribution Revenues $—
 $2
Purchased Electricity for Resale (64) (31)
Other Operation Expense —
 (13)
Maintenance Expense —
 (2)
Property, Plant and Equipment —
 (5)
Regulatory Assets/(Liabilities), Net (a) (228) (108)
Subtotal - Commodity (292) (157)
   
  
Interest Rate and Foreign Currency:  
  
Interest Expense 390
 389
Subtotal - Interest Rate and Foreign Currency 390
 389
     
Reclassifications from AOCI, before Income Tax (Expense) Credit 98
 232
Income Tax (Expense) Credit 35
 81
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 63
 151
     
Pension and OPEB  
  
Amortization of Prior Service Cost (Credit) (1,283) (1,283)
Amortization of Actuarial (Gains)/Losses 770
 1,834
Reclassifications from AOCI, before Income Tax (Expense) Credit (513) 551
Income Tax (Expense) Credit (180) 193
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (333) 358
   
  
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $(270) $509


177


APCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Six Months Ended June 30, 2014 and 2013
  Amount of (Gain) Loss
Reclassified from AOCI
  Six Months Ended June 30,
  2014 2013
Gains and Losses on Cash Flow Hedges (in thousands)
Commodity:  
  
Electric Generation, Transmission and Distribution Revenues $—
 $22
Purchased Electricity for Resale (526) 26
Other Operation Expense (10) (24)
Maintenance Expense (20) (18)
Property, Plant and Equipment (17) (19)
Regulatory Assets/(Liabilities), Net (a) (2,165) 181
Subtotal - Commodity (2,738) 168
   
  
Interest Rate and Foreign Currency:  
  
Interest Expense 780
 779
Subtotal - Interest Rate and Foreign Currency 780
 779
     
Reclassifications from AOCI, before Income Tax (Expense) Credit (1,958) 947
Income Tax (Expense) Credit (684) 331
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1,274) 616
     
Pension and OPEB  
  
Amortization of Prior Service Cost (Credit) (2,565) (2,565)
Amortization of Actuarial (Gains)/Losses 1,540
 3,667
Reclassifications from AOCI, before Income Tax (Expense) Credit (1,025) 1,102
Income Tax (Expense) Credit (359) 386
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (666) 716
   
  
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $(1,940) $1,332


178


I&M

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended June 30, 2014 and 2013
  Amount of (Gain) Loss
Reclassified from AOCI
  Three Months Ended June 30,
  2014 2013
Gains and Losses on Cash Flow Hedges (in thousands)
Commodity:  
  
Electric Generation, Transmission and Distribution Revenues $—
 $32
Purchased Electricity for Resale (95) (81)
Other Operation Expense —
 (8)
Maintenance Expense —
 (2)
Property, Plant and Equipment —
 (3)
Regulatory Assets/(Liabilities), Net (a) (103) (12)
Subtotal - Commodity (198) (74)
   
  
Interest Rate and Foreign Currency:  
  
Interest Expense 631
 631
Subtotal - Interest Rate and Foreign Currency 631
 631
     
Reclassifications from AOCI, before Income Tax (Expense) Credit 433
 557
Income Tax (Expense) Credit 151
 195
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 282
 362
     
Pension and OPEB  
  
Amortization of Prior Service Cost (Credit) (198) (198)
Amortization of Actuarial (Gains)/Losses 262
 468
Reclassifications from AOCI, before Income Tax (Expense) Credit 64
 270
Income Tax (Expense) Credit 21
 95
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 43
 175
   
  
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $325
 $537


179


I&M

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Six Months Ended June 30, 2014 and 2013
  Amount of (Gain) Loss
Reclassified from AOCI
  Six Months Ended June 30,
  2014 2013
Gains and Losses on Cash Flow Hedges (in thousands)
Commodity:  
  
Electric Generation, Transmission and Distribution Revenues $—
 $84
Purchased Electricity for Resale (812) 68
Other Operation Expense (7) (15)
Maintenance Expense (7) (9)
Property, Plant and Equipment (10) (10)
Regulatory Assets/(Liabilities), Net (a) (973) 38
Subtotal - Commodity (1,809) 156
   
  
Interest Rate and Foreign Currency:  
  
Interest Expense 1,262
 927
Subtotal - Interest Rate and Foreign Currency 1,262
 927
     
Reclassifications from AOCI, before Income Tax (Expense) Credit (547) 1,083
Income Tax (Expense) Credit (192) 379
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (355) 704
     
Pension and OPEB  
  
Amortization of Prior Service Cost (Credit) (397) (397)
Amortization of Actuarial (Gains)/Losses 527
 937
Reclassifications from AOCI, before Income Tax (Expense) Credit 130
 540
Income Tax (Expense) Credit 44
 189
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 86
 351
   
  
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $(269) $1,055


180


OPCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended June 30, 2014 and 2013
  Amount of (Gain) Loss
Reclassified from AOCI
  Three Months Ended June 30,
  2014 2013
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 (3) 1
Interest Expense (524) (525)
Subtotal - Interest Rate and Foreign Currency (527) (524)
     
Reclassifications from AOCI, before Income Tax (Expense) Credit (527) (671)
Income Tax (Expense) Credit (184) (235)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (343) (436)
     
Pension and OPEB  
  
Amortization of Prior Service Cost (Credit) —
 (1,469)
Amortization of 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 $(343) $2,834


181


OPCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Six Months Ended June 30, 2014 and 2013
  Amount of (Gain) Loss
Reclassified from AOCI
  Six Months Ended June 30,
  2014 2013
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 (11) (37)
Maintenance Expense (11) (15)
Property, Plant and Equipment (18) (23)
Regulatory Assets/(Liabilities), Net (a) (122) —
Subtotal - Commodity (162) 320
   
  
Interest Rate and Foreign Currency:  
  
Depreciation and Amortization Expense (6) 3
Interest Expense (1,048) (1,049)
Subtotal - Interest Rate and Foreign Currency (1,054) (1,046)
     
Reclassifications from AOCI, before Income Tax (Expense) Credit (1,216) (726)
Income Tax (Expense) Credit (425) (254)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (791) (472)
     
Pension and OPEB  
  
Amortization of Prior Service Cost (Credit) —
 (2,937)
Amortization of 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 $(791) $6,067


182


PSO

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended June 30, 2014 and 2013
  Amount of (Gain) Loss
Reclassified from AOCI
  Three Months Ended June 30,
  2014 2013
Gains and Losses on Cash Flow Hedges (in thousands)
Commodity:  
  
Other Operation Expense $—
 $(6)
Subtotal - Commodity —
 (6)
   
  
Interest Rate and Foreign Currency:  
  
Interest Expense (292) (292)
Subtotal - Interest Rate and Foreign Currency (292) (292)
     
Reclassifications from AOCI, before Income Tax (Expense) Credit (292) (298)
Income Tax (Expense) Credit (102) (104)
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $(190) $(194)
PSO

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Six Months Ended June 30, 2014 and 2013
  Amount of (Gain) Loss
Reclassified from AOCI
  Six Months Ended June 30,
  2014 2013
Gains and Losses on Cash Flow Hedges (in thousands)
Commodity:  
  
Other Operation Expense $(8) $(15)
Maintenance Expense (9) (4)
Property, Plant and Equipment (13) (7)
Regulatory Assets/(Liabilities), Net (a) (58) —
Subtotal - Commodity (88) (26)
   
  
Interest Rate and Foreign Currency:  
  
Interest Expense (584) (584)
Subtotal - Interest Rate and Foreign Currency (584) (584)
     
Reclassifications from AOCI, before Income Tax (Expense) Credit (672) (610)
Income Tax (Expense) Credit (236) (213)
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $(436) $(397)


183


SWEPCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended June 30, 2014 and 2013
  Amount of (Gain) Loss
Reclassified from AOCI
  Three Months Ended June 30,
  2014 2013
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
 872
Subtotal - Interest Rate and Foreign Currency 872
 872
     
Reclassifications from AOCI, before Income Tax (Expense) Credit 872
 864
Income Tax (Expense) Credit 305
 303
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 567
 561
     
Pension and OPEB  
  
Amortization of Prior Service Cost (Credit) (477) (447)
Amortization of Actuarial (Gains)/Losses 115
 348
Reclassifications from AOCI, before Income Tax (Expense) Credit (362) (99)
Income Tax (Expense) Credit (127) (35)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (235) (64)
   
  
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $332
 $497

184


SWEPCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Six Months Ended June 30, 2014 and 2013
  Amount of (Gain) Loss
Reclassified from AOCI
  Six Months Ended June 30,
  2014 2013
Gains and Losses on Cash Flow Hedges (in thousands)
Commodity:  
  
Other Operation Expense $(13) $(16)
Maintenance Expense (10) (7)
Property, Plant and Equipment (11) (8)
Regulatory Assets/(Liabilities), Net (a) (67) —
Subtotal - Commodity (101) (31)
   
  
Interest Rate and Foreign Currency:  
  
Interest Expense 1,744
 1,744
Subtotal - Interest Rate and Foreign Currency 1,744
 1,744
     
Reclassifications from AOCI, before Income Tax (Expense) Credit 1,643
 1,713
Income Tax (Expense) Credit 574
 600
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,069
 1,113
     
Pension and OPEB  
  
Amortization of Prior Service Cost (Credit) (955) (892)
Amortization of Actuarial (Gains)/Losses 233
 696
Reclassifications from AOCI, before Income Tax (Expense) Credit (722) (196)
Income Tax (Expense) Credit (253) (69)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (469) (127)
   
  
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $600
 $986
(a)Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.


185


4.  RATE MATTERS

As discussed in the 2013 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 2013 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 2014 and updates the 2013 Annual Report.

Regulatory Assets Pending Final Regulatory Approval
  APCo
  June 30, December 31,
  2014 2013
Noncurrent Regulatory Assets (in thousands)
     
Regulatory Assets Currently Earning a Return    
West Virginia Vegetation Management Program $6,458
 $—
Regulatory Assets Currently Not Earning a Return    
Storm Related Costs 65,206
 65,206
IGCC Pre-Construction Costs 20,528
 —
Expanded Net Energy Charge - Coal Inventory 13,686
 20,528
Mountaineer Carbon Capture and Storage Product Validation Facility 13,264
 13,264
Virginia Demand Response Program Costs 6,767
 5,012
Virginia Environmental Rate Adjustment Clause 1,941
 2,440
Mountaineer Carbon Capture and Storage Commercial Scale Facility 1,287
 1,287
Transmission Agreement Phase-In —
 3,313
Other Regulatory Assets Pending Final Regulatory Approval 1,109
 168
Total Regulatory Assets Pending Final Regulatory Approval $130,246
 $111,218
  I&M
  June 30, December 31,
  2014 2013
Noncurrent Regulatory Assets (in thousands)
     
Regulatory Assets Currently Not Earning a Return    
Cook Plant Turbine $5,024
 $3,452
Stranded Costs on Abandoned Plants 3,897
 3,896
Indiana Deferred Cook Plant Life Cycle Management Project Costs —
 4,093
Indiana Under-Recovered Capacity Costs —
 21,945
Storm Related Costs —
 1,836
Other Regulatory Assets Pending Final Regulatory Approval 1,549
 164
Total Regulatory Assets Pending Final Regulatory Approval $10,470
 $35,386
  OPCo
  June 30, December 31,
  2014 2013
Noncurrent Regulatory Assets (in thousands)
     
Regulatory Assets Currently Earning a Return    
Ohio Economic Development Rider $—
 $13,854
Regulatory Assets Currently Not Earning a Return  
  
Ormet Special Rate Recovery Mechanism 10,483
 35,631
Storm Related Costs 386
 57,589
Total Regulatory Assets Pending Final Regulatory Approval $10,869
 $107,074

186


  PSO
  June 30, December 31,
  2014 2013
Noncurrent Regulatory Assets (in thousands)
     
Regulatory Assets Currently Not Earning a Return  
  
Storm Related Costs $15,589
 $18,743
Other Regulatory Assets Pending Final Regulatory Approval 1,079
 845
Total Regulatory Assets Pending Final Regulatory Approval $16,668
 $19,588
  SWEPCo
  June 30, December 31,
  2014 2013
Noncurrent Regulatory Assets (in thousands)
     
Regulatory Assets Currently Not Earning a Return    
Rate Case Expenses $7,989
 $7,934
Mountaineer Carbon Capture and Storage Commercial Scale Facility 1,143
 1,143
Other Regulatory Assets Pending Final Regulatory Approval 2,101
 1,951
Total Regulatory Assets Pending Final Regulatory Approval $11,233
 $11,028

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 Filings

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 (OCC) 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. In February 2014, the Supreme Court of Ohio affirmed the PUCO’s decision and rejected all appeals filed by the OCC and the IEU. In February 2014, the IEU filed for reconsideration of the Supreme Court of Ohio decision, which was subsequently denied in May 2014. As of June 30, 2014, OPCo’s net deferred fuel balance was $411 million, excluding unrecognized equity carrying costs.

In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital rate. In November 2012, the IEU and the OCC filed appeals regarding the PUCO

187


decision in the PIRR proceeding. These appeals principally argued that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo’s net deferred fuel balance up to the full amount. These intervenors’ appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of June 30, 2014, could reduce carrying costs by $29 million including $15 million of unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending.

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

June 2012 – May 2015 ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015. This ruling 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 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 OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and is $150/MW day from June 2014 through May 2015.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.  

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR was collected from customers at $3.50/MWh through May 2014 and is currently collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. As of June 30, 2014, OPCo's incurred deferred capacity costs balance of $396 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

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

In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications which included the delay of the energy auctions that were originally ordered in the ESP order. As ordered, in February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. Also as ordered, in May 2014, OPCo conducted an additional energy-only auction for 25% of the SSO load with delivery beginning November 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 25% of the SSO load with delivery beginning November 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. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In May 2014, an independent auditor was selected by the PUCO and an audit of the recovery of the fixed fuel costs began in June 2014. A final audit report is expected in the third quarter of 2014.


188


Proposed June 2015 - May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to competitively procured SSO supply. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo. The proposal also includes a purchased power agreement rider (PPA) that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based purchase power agreement. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. Additionally, in July 2014, OPCo submitted a separate application to continue the RSR established in the June 2012 - May 2015 ESP to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. In May 2014, intervenors and the PUCO staff filed testimony that provided various recommendations including the rejection and/or modification of various riders, including the DIR and the proposed PPA. Hearings at the PUCO in the ESP case were held in June 2014.

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

Significantly Excessive Earnings Test (SEET) Filings

In January 2011, the PUCO issued an order on the 2009 SEET filing. The 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. In September 2013, a proposed second phase of OPCo’s gridSMART® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending.

In November 2013, OPCo filed its 2011 and 2012 SEET filingfilings with the PUCO.  OPCo was required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. In March 2014, the PUCO approved a stipulation agreement between OPCo and the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2011 for CSPCo or OPCo.

In November 2013, OPCo filed its 2012 SEET filing withMay 2014, the PUCO.  In April 2014, OPCo entered intoPUCO approved a stipulation agreement withbetween OPCo and the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2012 for OPCo. A hearing at the PUCO related to the 2012In May 2014, OPCo filed its 2013 SEET filing is scheduled for April 2014.with the PUCO. Management does not believe that there were significantly excessive earnings in 2013 for OPCo.2013.

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 and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo’s generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition.

Storm Damage Recovery Rider (SDRR)

In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates to recover 2012 incremental storm distribution expenses over twelve months starting withexpenses. In April 2014, the effective date asPUCO approved by the PUCO.  In December 2013, a stipulation agreement was reached between OPCo, the PUCO staff and all intervenors, except the OCC.  The stipulation agreement recommended approvalOCC, to recover $55 million related to 2012 storm costs over a 12-month period which included a $6 million reduction in the amount of 2012 storm expenses to be recovered.period. The agreement also provided that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period. In April 2014, the PUCO approved the settlement agreement.  Compliance tariffs were filed with the PUCO and new rates were implemented in April 2014. In May 2014, the PUCO upheld the settlement agreement on rehearing.

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2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo’s 2009 FAC 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. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 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. 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.

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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 Ohioultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC). The PUCO subsequently ruled in the PIRR proceeding that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes. Hearings at the PUCO were held in November 2013.  If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition.  See the 2009 –- 2011 ESP section of the “Ohio Electric Security Plan Filing” related to the PUCO order in the PIRR proceeding. In May 2014, the PUCO issued an order that generally approved OPCo's 2010-2011 fuel costs. The order rejected the auditor recommendation to adjust the WACC carrying charges related to accumulated deferred income taxes. Additionally, the PUCO requested further review related to an affiliate barging agreement and the modification of certain fuel procurement processes and practices.Further, the order provided for the auditor to address any remaining concerns in their next audit report, as they deem necessary. OPCo opposed these additional conditions in its application for rehearing in June 2014. In June 2014, the IEU filed an application with the PUCO for rehearing of this May 2014 order. In July 2014, the PUCO issued an order that denied all requests for rehearing.

2012 –and 2013 Fuel Adjustment Clause Audits

In AprilMay 2014, the PUCO-selected outside consultant provided its preliminary draftfinal report related to theirits 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the pending audit of the recovery of fixed fuel costs. See the "June 2012 – May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition.

Ormet

Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware.  In October 2013, Ormet announced that it was unable to emerge from bankruptcyDelaware and subsequently shut down operations effective immediately.in October 2013. Based upon previous PUCO rulings providing rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider (EDR), except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet’s October and November 2012 power bills. OPCo expects that any additional unpaid generation usage by Ormet will be recoverable as a regulatory asset through the EDR. In February 2014, a stipulation agreement between OPCo and Ormet was filed with the PUCO. The stipulation recommendsrecommended approval of OPCo’s right to fully recover approximately $49 million

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of foregone revenues through the EDR which, as of March 31, 2014, is recorded in regulatory assets on the balance sheet.EDR. Also in February 2014, intervenor comments were filed objecting to full recovery of these foregone revenues. In March 2014, the PUCO issued an order in OPCo’s EDR filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals.deferrals which, as of June 30, 2014, is recorded in regulatory assets on the balance sheet. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement is scheduled forwas held in May 2014.

In addition, in the 2009 –- 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.

To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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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 March 31,June 30, 2014, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting that OPCo refund all collected pre-construction costs to Ohio ratepayers with interest.

Management cannot predict the outcome of this proceeding concerning the Ohio IGCC plant or what effect, if any, this proceeding 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

2012 Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In October 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of March 31,June 30, 2014, the net book value of Welsh Plant, Unit 2 was $86$85 million, before cost of removal, including materials and supplies inventory and CWIP.

Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase is approximately $52 million. In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling.  Thisruling and in April 2014, this order became finalfinal. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and appealable in April 2014.filed initial responses.

If any part of the PUCT order is overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs of Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

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2013 Texas Transmission Cost Recovery Factor Filing

In December 2013,May 2014, SWEPCo filed an application with the PUCT to implement its initial transmission cost recovery factor (TCRF) requesting additional annual revenue of $10$15 million. The TCRF is designed to recover increases from the amounts included in SWEPCo’s Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC. SWEPCo’s application included Turk Plant transmission-related costs. In MarchJuly 2014, intervenors filed testimony with recommendations that included decreases ranging from $5 million to $14 million to the Administrative Law Judge (ALJ) dismissed this case without prejudice.  The ALJ concluded that SWEPCo’s application was premature asrequested annual revenue. A hearing at the PUCT had not completed its ruling onis scheduled for August 2014. An order is anticipated in the motions for rehearingfourth quarter of 2014. If the PUCT were to disallow any portion of the order in the SWEPCo Texas Base Rate Case in which the baseline values to be used in the TCRF, calculation would be established.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. The rates are subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In May 2013, SWEPCo filed testimony in
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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.

2014 Louisiana Formula Rate Filing

In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC.  The filing included a $5 million annual increase to be effective August 2014.  SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchase power agreement attributable to Louisiana customers.  These increases are subject to LPSC staff review.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC.  Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC.  As of June 30, 2014, SWEPCo has incurred $72 million in costs related to these projects.  SWEPCo will seek to recover these project costs from customers through filings at the state commissions and FERC. These environmental projects could be impacted by pending carbon emission regulations.  As of June 30, 2014, the net book value of Welsh Plant, Units 1 and 3 was $297 million, before cost of removal, including materials and supplies inventory and CWIP.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 

APCo Rate Matters

Plant Transfer

In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge

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of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo.WPCo until APCo's West Virginia base rates are updated. See the "2014 West Virginia Base Rate Case" below. In April 2014, APCoAGR and WPCo also filed a request with the FERC for approval to transfer AGR’s one-half interest in the Mitchell Plant to WPCo. Upon transferIn June 2014, the FERC issued an order approving this request. Also in June 2014, an intervenor filed a motion to stay the proceeding at the WVPSC until alternatives to the acquisition of the Mitchell Plant have been explored. In accordance with a July 2014 order addressing the motion to WPCo, WPCo will no longer purchase power from AGR.stay, APCo filed supplemental testimony to address intervenor concerns. In July 2014, the WVPSC issued an order that modified the procedural schedule. A hearing at the WVPSC is scheduled for September 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

APCo IGCC Plant

As of March 31,June 30, 2014, 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.  In March 2014, APCo submitted a request to the Virginia SCC as part of the 2014 Virginia Biennial Base Rate Case to amortize the Virginia jurisdictional share of these costs over two years. In June 2014, APCo submitted a request to the WVPSC as part of the 2014 West Virginia Base Rate Case to amortize the West Virginia jurisdictional share of these costs over five years. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Transmission Rate Adjustment Clause (transmission RAC)

In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually to be effective May 2014. In March 2014, the Virginia SCC issued an order approving a stipulation agreement between APCo and the Virginia SCC staff increasing the transmission RAC revenues by $49 million annually, subject to true-up, effective May 2014. Pursuant to the order, the Virginia SCC staff will audit APCo’s transmission RAC under-recoveries and report its findings and recommendations in testimony in APCo’s next transmission RAC proceeding in 2015.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a biennial generation and distribution base rate biennial reviewcase with the Virginia SCC. In accordance with a Virginia statute, APCo did not request a change in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to changes in the expected service lives of various generating units and the extended recovery through 2040 of the net book value of certain planned 2015 plant retirements. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to certainIGCC and other deferred costs. A hearing at the Virginia SCC is scheduled for September 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2014 West Virginia Base Rate Case
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In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $156 million, based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units. The filing also requested amortization of $77 million over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $38 million annually to recover total vegetation management costs. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting authority to merge WPCo into

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APCo. In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC. In April 2013, the FERC approved the merger. Also in December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval 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. In June 2013, the WVPSC issued an order consolidating the merger case with APCo’s plant asset transfer case. In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo. In December 2013, the WVPSC issued an order that deferred ruling on the merger of WPCo into APCo. The order also directed APCo and WPCo to submit a plan with the WVPSC identifying a course of action to serve the load of WPCo. See the “Plant Transfer” section of APCo Rate Matters. The feasibility of the merger remains under review.

PSO Rate Matters

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years.

In April and May 2014, testimony was filed by the OCC Staffstaff and intervenors filed testimony with recommendations that included adjustments to annual base rates ranging from an increase of $16$16 million to a reduction of $22$22 million, primarily based upon the determination of depreciation rates and a return on common equity between 9.18% and 9.5%. Additionally, the recommendations did not support the advanced metering rider or the expansion of the transmission rider. In May 2014, PSO filed rebuttal testimony that included an updated annual base rate increase request of $42 million to reflect certain updated costs.

In June 2014, a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors was filed with the OCC. The parties to the stipulation recommended no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider would provide $7 million of revenues in 2014 and increases to $27 million in 2016. New depreciation rates are recommended for advanced metering investments and existing meters, to be effective November 2014. Further, the stipulation recommends a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring and for riders with an equity component. Additionally, the stipulation recommends recovery of regulatory assets for 2013 storms and regulatory case expenses. In July 2014, the Attorney General joined in the stipulation agreement. A hearing at the OCC is scheduled for Junewas held in July 2014. If the OCC were to disallow any portion of this base rate request,settlement agreement, 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% and adjusted the authorized annual increase in base rates to $92 million in March 2013.  In March 2013,April 2014, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the order with the Indiana Court of Appeals.  In March 2014, the Indiana Court of Appeals upheld the February 2013 IURC order.  In April 2014, the OUCC filed an appeal to the Indiana Supreme Court related to the inclusion of a prepaid pension asset in rate base.base, which is approximately $7 million in annual revenues. If any part of the IURC order is overturned by the Indiana Supreme Court, it could reduce future net income and cash flows.flows and impact financial condition.


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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 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 March 31,June 30, 2014, I&M has incurred costs of $405$439 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to
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certain projects effective January 2012 to the extent such costs are not reflected in rates. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC. In May 2014, the IURC issued a final order approving the LCM rider rates that were implemented in January 2014.

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

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

Tanners Creek Plant Units 1 - 4

In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations. In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas. I&M is currently recovering depreciation and a return on the net book value of the Tanners Creek Plant in base rates and plans to seek recovery of all of the plant’s retirement related costs in its next Indiana and Michigan base rate cases.

In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015. Upon the retirement of the Tanners Creek Plant, I&M proposesproposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant will be recovered over the remaining life of the Rockport Plant. I&M requested to have the impact of these new depreciation rates incorporated into the rates set in its next rate case.case where I&M will also seek continued recovery of a return on the net book value of the Tanners Creek Plant. The new depreciation rates are expected towould result in a decrease in I&M’s Michigan jurisdictional electric depreciation expense which I&M proposesproposed to implement in the month following a MPSC order in the revised depreciation case.order. A hearing at the MPSC is scheduled for September 2014.

As of March 31,June 30, 2014, the net book value of the Tanners Creek Plant was $334$327 million, before cost of removal, including materials and supplies inventory and CWIP. If I&M is ultimately not permitted to fully recover its net book value of the Tanners Creek Plant and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition.


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5.  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 2013 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 SWEPCoOPCo

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.

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AEP has two revolving credit facilities totaling $3.5 billion, under which up to $1.2 billion may be issued as letters of credit.  As of March 31,June 30, 2014, the maximum future payments for letters of credit issued under the revolving credit facilities were as follows:

CompanyAmountMaturity
(in thousands)
I&M$ 150 March 2015
OPCo 3,081 June 2014
Company Amount Maturity
  (in thousands)  
I&M $150
 March 2015
OPCo 4,200
 June 2015

The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows:

    Bilateral Maturity of
 Pollution Letters Bilateral Letters
Company Control Bonds of Credit of Credit 
Pollution
Control Bonds
 
Bilateral Letters
of Credit
 
Maturity of Bilateral
Letters of Credit
 (in thousands)   (in thousands)  
APCo $229,650  $ 232,293  March 2016 to March 2017  $229,650
 $232,293
 March 2016 to March 2017 
I&M  77,000    77,886  March 2015 77,000
 77,886
 March 2015

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 March 31,June 30, 2014, SWEPCo has collected approximately $62$63 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $46$47 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed balance sheets.

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

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

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of March 31,June 30, 2014, there were no material liabilities recorded for any indemnifications.

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

Master Lease Agreements

The Registrant Subsidiaries lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual
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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 March 31,June 30, 2014, 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
CompanyPotential Loss
(in thousands)
APCo$ 3,772 
I&M 2,580 
OPCo 4,384 
PSO 1,347 
SWEPCo 2,486 
Company 
Maximum
Potential Loss
  (in thousands)
APCo $3,671
I&M 2,618
OPCo 4,161
PSO 1,505
SWEPCo 2,438

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$12 million and $15$14 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31,June 30, 2014.

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.


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ENVIRONMENTAL CONTINGENCIES

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 generation 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 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 $8$7 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
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requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generatinggeneration 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.

OPERATIONAL CONTINGENCIES

Rockport Plant Litigation – Affecting I&M

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

Wage and Hours Lawsuit – Affecting PSO

In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act.  Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked.  Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs.  Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount.


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In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action.  Notice was given to all class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Management will continue to defend the case. Management is unable to determine a range of potential losses that are reasonably possible of occurring.




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6.  DISPOSITION AND IMPAIRMENT

DISPOSITION

2013

Conesville Coal Preparation Facility – Affecting OPCo

In April 2013, OPCo closed on the sale of its Conesville Coal Preparation facility.  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 will retire the plant in 2015.


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7.  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 March 31,June 30, 2014 and 2013:

APCo           
   Other Postretirement
 Pension Plans Benefit Plans
 Three Months Ended March 31, Three Months Ended March 31,
 2014  2013  2014  2013 
 (in thousands)
Service Cost$ 1,759  $ 1,543  $ 362  $ 641 
Interest Cost  7,406    6,916    3,197    3,363 
Expected Return on Plan Assets  (8,482)   (9,260)   (4,633)   (4,536)
Amortization of Prior Service Cost (Credit)  50    49    (2,513)   (2,512)
Amortization of Net Actuarial Loss  4,148    6,256    1,146    3,062 
Net Periodic Benefit Cost (Credit)$ 4,881  $ 5,504  $ (2,441) $ 18 
APCo
 Pension Plans 
Other Postretirement
Benefit Plans
 Three Months Ended Three Months Ended
 June 30, June 30,
 2014
2013 2014 2013
 (in thousands)
Service Cost$1,759
 $1,542
 $362
 $642
Interest Cost7,406
 6,915
 3,197
 3,364
Expected Return on Plan Assets(8,481) (9,260) (4,633) (4,537)
Amortization of Prior Service Cost (Credit)49
 50
 (2,512) (2,513)
Amortization of Net Actuarial Loss4,148
 6,257
 1,145
 3,062
Net Periodic Benefit Cost (Credit)$4,881
 $5,504
 $(2,441) $18
 Pension Plans 
Other Postretirement
Benefit Plans
 Six Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in thousands)
Service Cost$3,518
 $3,085
 $724
 $1,283
Interest Cost14,812
 13,831
 6,394
 6,727
Expected Return on Plan Assets(16,963) (18,520) (9,266) (9,073)
Amortization of Prior Service Cost (Credit)99
 99
 (5,025) (5,025)
Amortization of Net Actuarial Loss8,296
 12,513
 2,291
 6,124
Net Periodic Benefit Cost (Credit)$9,762
 $11,008
 $(4,882) $36


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I&M
 Pension Plans 
Other Postretirement
Benefit Plans
 Three Months Ended Three Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in thousands)
Service Cost$2,517
 $2,184
 $487
 $805
Interest Cost6,574
 6,025
 1,910
 2,055
Expected Return on Plan Assets(7,748) (8,206) (3,363) (3,296)
Amortization of Prior Service Cost (Credit)48
 48
 (2,356) (2,355)
Amortization of Net Actuarial Loss3,646
 5,422
 592
 1,881
Net Periodic Benefit Cost (Credit)$5,037
 $5,473
 $(2,730) $(910)
 Pension Plans 
Other Postretirement
Benefit Plans
 Six Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in thousands)
Service Cost$5,034
 $4,368
 $974
 $1,610
Interest Cost13,147
 12,050
 3,819
 4,110
Expected Return on Plan Assets(15,496) (16,413) (6,727) (6,592)
Amortization of Prior Service Cost (Credit)97
 97
 (4,711) (4,710)
Amortization of Net Actuarial Loss7,292
 10,844
 1,184
 3,763
Net Periodic Benefit Cost (Credit)$10,074
 $10,946
 $(5,461) $(1,819)

OPCo
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 Pension Plans 
Other Postretirement
Benefit Plans
 Three Months Ended Three Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in thousands)
Service Cost$1,285
 $2,373
 $257
 $1,299
Interest Cost5,526
 10,292
 1,900
 4,447
Expected Return on Plan Assets(6,606) (15,142) (3,380) (6,239)
Amortization of Prior Service Cost (Credit)39
 70
 (1,730) (3,230)
Amortization of Net Actuarial Loss3,105
 9,309
 595
 4,041
Net Periodic Benefit Cost (Credit)$3,349
 $6,902
 $(2,358) $318
 Pension Plans 
Other Postretirement
Benefit Plans
 Six Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in thousands)
Service Cost$2,570
 $4,745
 $513
 $2,599
Interest Cost11,052
 20,584
 3,801
 8,894
Expected Return on Plan Assets(13,213) (30,283) (6,760) (12,477)
Amortization of Prior Service Cost (Credit)78
 141
 (3,461) (6,461)
Amortization of Net Actuarial Loss6,211
 18,618
 1,190
 8,082
Net Periodic Benefit Cost (Credit)$6,698
 $13,805
 $(4,717) $637


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PSO
I&M           
  Other PostretirementPension Plans 
Other Postretirement
Benefit Plans
Pension Plans Benefit PlansThree Months Ended Three Months Ended
Three Months Ended March 31, Three Months Ended March 31,June 30, June 30,
2014  2013  2014  2013 2014 2013 2014 2013
(in thousands)(in thousands)
Service Cost$ 2,517  $ 2,184  $ 487  $ 805 $1,302
 $1,390
 $210
 $343
Interest Cost  6,573    6,025    1,909    2,055 3,014
 2,749
 894
 948
Expected Return on Plan Assets  (7,748)   (8,207)   (3,364)   (3,296)(3,651) (3,919) (1,575) (1,522)
Amortization of Prior Service Cost (Credit)  49    49    (2,355)   (2,355)74
 74
 (1,073) (1,073)
Amortization of Net Actuarial Loss  3,646    5,422    592    1,882 1,688
 2,461
 277
 869
Net Periodic Benefit Cost (Credit)$ 5,037  $ 5,473  $ (2,731) $ (909)$2,427
 $2,755
 $(1,267) $(435)
 Pension Plans 
Other Postretirement
Benefit Plans
 Six Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in thousands)
Service Cost$2,604
 $2,781
 $420
 $686
Interest Cost6,028
 5,497
 1,787
 1,896
Expected Return on Plan Assets(7,302) (7,837) (3,150) (3,044)
Amortization of Prior Service Cost (Credit)148
 148
 (2,145) (2,145)
Amortization of Net Actuarial Loss3,376
 4,922
 554
 1,738
Net Periodic Benefit Cost (Credit)$4,854
 $5,511
 $(2,534) $(869)

OPCo           
   Other Postretirement
 Pension Plans Benefit Plans
 Three Months Ended March 31, Three Months Ended March 31,
 2014  2013  2014  2013 
 (in thousands)
Service Cost$ 1,285  $ 2,372  $ 256  $ 1,300 
Interest Cost  5,526    10,292    1,901    4,447 
Expected Return on Plan Assets  (6,607)   (15,141)   (3,380)   (6,238)
Amortization of Prior Service Cost (Credit)  39    71    (1,731)   (3,231)
Amortization of Net Actuarial Loss  3,106    9,309    595    4,041 
Net Periodic Benefit Cost (Credit)$ 3,349  $ 6,903  $ (2,359) $ 319 
SWEPCo
 Pension Plans 
Other Postretirement
Benefit Plans
 Three Months Ended Three Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in thousands)
Service Cost$1,654
 $1,753
 $253
 $423
Interest Cost3,162
 2,863
 998
 1,076
Expected Return on Plan Assets(3,857) (4,128) (1,754) (1,720)
Amortization of Prior Service Cost (Credit)88
 88
 (1,289) (1,290)
Amortization of Net Actuarial Loss1,762
 2,554
 308
 982
Net Periodic Benefit Cost (Credit)$2,809
 $3,130
 $(1,484) $(529)
 Pension Plans 
Other Postretirement
Benefit Plans
 Six Months Ended Six Months Ended
 June 30, June 30,
 2014 2013 2014 2013
 (in thousands)
Service Cost$3,309
 $3,506
 $506
 $846
Interest Cost6,325
 5,727
 1,996
 2,151
Expected Return on Plan Assets(7,714) (8,255) (3,508) (3,440)
Amortization of Prior Service Cost (Credit)175
 175
 (2,578) (2,578)
Amortization of Net Actuarial Loss3,523
 5,107
 617
 1,964
Net Periodic Benefit Cost (Credit)$5,618
 $6,260
 $(2,967) $(1,057)


PSO           
   Other Postretirement
 Pension Plans Benefit Plans
 Three Months Ended March 31, Three Months Ended March 31,
 2014  2013  2014  2013 
 (in thousands)
Service Cost$ 1,302  $ 1,391  $ 210  $ 343 
Interest Cost  3,014    2,748    893    948 
Expected Return on Plan Assets  (3,651)   (3,918)   (1,575)   (1,522)
Amortization of Prior Service Cost (Credit)  74    74    (1,072)   (1,072)
Amortization of Net Actuarial Loss  1,688    2,461    277    869 
Net Periodic Benefit Cost (Credit)$ 2,427  $ 2,756  $ (1,267) $ (434)
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SWEPCo           
   Other Postretirement
 Pension Plans Benefit Plans
 Three Months Ended March 31, Three Months Ended March 31,
 2014  2013  2014  2013 
 (in thousands)
Service Cost$ 1,655  $ 1,753  $ 253  $ 423 
Interest Cost  3,163    2,864    998    1,075 
Expected Return on Plan Assets  (3,857)   (4,127)   (1,754)   (1,720)
Amortization of Prior Service Cost (Credit)  87    87    (1,289)   (1,288)
Amortization of Net Actuarial Loss  1,761    2,553    309    982 
Net Periodic Benefit Cost (Credit)$ 2,809  $ 3,130  $ (1,483) $ (528)

7.  8.  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.  9.  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, natural gas, 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 extent, heating oil, gasoline 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.

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The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of March 31,June 30, 2014 and December 31, 2013:

Notional Volume of Derivative Instruments
March 31, 2014
                    
Primary Risk Unit of               
Exposure Measure APCo I&M OPCo PSO SWEPCo
      (in thousands)
Commodity:                 
 Power MWhs   29,680    19,636    12,108    9,251    11,716 
 Coal Tons   186    2,666    -    750    1,292 
 Natural Gas MMBtus   1,934    1,312    -    -    - 
 Heating Oil and                 
  Gasoline Gallons   792    379    806    446    508 
 Interest Rate USD $ 10,877  $ 7,378  $ -  $ -  $ - 
                    
Interest Rate and                 
 Foreign Currency USD $ -  $ -  $ -  $ -  $ - 
                    
Notional Volume of Derivative Instruments
December 31, 2013
                    
Primary Risk Unit of               
Exposure Measure APCo I&M OPCo PSO SWEPCo
      (in thousands)
Commodity:                 
 Power MWhs   48,995    33,231    34,843    13,469    17,057 
 Coal Tons   31    3,389    -    1,013    1,692 
 Natural Gas MMBtus   2,477    1,680    -    -    - 
 Heating Oil and                 
  Gasoline Gallons   1,089    521    1,108    614    699 
 Interest Rate USD $ 12,720  $ 8,627  $ -  $ -  $ - 
                    
Interest Rate and                 
 Foreign Currency USD $ -  $ -  $ -  $ -  $ - 
Notional Volume of Derivative Instruments
June 30, 2014
Primary Risk
Exposure
 
Unit of
Measure
 APCo I&M OPCo PSO SWEPCo
    (in thousands)
Commodity:      
  
  
  
Power MWhs 67,059
 48,352
 32,686
 14,744
 18,668
Coal Tons 465
 1,778
 —
 500
 917
Natural Gas MMBtus 1,540
 1,030
 —
 68
 87
Heating Oil and Gasoline Gallons 891
 427
 907
 502
 572
Interest Rate USD $8,041
 $5,454
 $—
 $—
 $—


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Notional Volume of Derivative Instruments
December 31, 2013
Primary Risk
Exposure
 
Unit of
Measure
 APCo I&M OPCo PSO SWEPCo
    (in thousands)
Commodity:      
  
  
  
Power MWhs 48,995
 33,231
 34,843
 13,469
 17,057
Coal Tons 31
 3,389
 —
 1,013
 1,692
Natural Gas MMBtus 2,477
 1,680
 —
 —
 —
Heating Oil and Gasoline Gallons 1,089
 521
 1,108
 614
 699
Interest Rate USD $12,720
 $8,627
 $—
 $—
 $—

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 and natural gas (“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. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three and six months ended March 31,June 30, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As ofIn March 31, 2014, these contracts will bewere grouped as “Commodity”"Commodity" with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.


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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’scontract'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 March 31,June 30, 2014 and December 31, 2013 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:

   March 31, 2014 December 31, 2013
   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 $ 32  $ 1,362  $ -  $ 2,993 
I&M   21    924    -    2,030 
OPCo   3    -    -    - 
PSO   1    -    -    1 
SWEPCo   2    -    -    3 
  June 30, 2014 December 31, 2013
Company 
Cash Collateral
Received
Netted Against
Risk Management
Assets
 
Cash Collateral
Paid
Netted Against
Risk Management
Liabilities
 
Cash Collateral
Received
Netted Against
Risk Management
Assets
 
Cash Collateral
Paid
Netted Against
Risk Management
Liabilities
  (in thousands)
APCo $1,356
 $137
 $—
 $2,993
I&M 894
 333
 —
 2,030
OPCo 145
 —
 —
 —
PSO 72
 —
 —
 1
SWEPCo 83
 —
 —
 3

156
207


The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of March 31,June 30, 2014 and December 31, 2013:

APCo                  
Fair Value of Derivative Instruments
March 31, 2014
                    
   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 $34,483  $224  $-  $34,707  $(18,735) $15,972 
Long-term Risk Management Assets  17,304   -   -   17,304   (3,291)  14,013 
Total Assets  51,787   224   -   52,011   (22,026)  29,985 
                    
Current Risk Management Liabilities  24,273   90   -   24,363   (19,727)  4,636 
Long-term Risk Management Liabilities  11,558   -   -   11,558   (3,629)  7,929 
Total Liabilities  35,831   90   -   35,921   (23,356)  12,565 
                    
Total MTM Derivative Contract Net                  
 Assets (Liabilities) $15,956  $134  $-  $16,090  $1,330  $17,420 
                    
APCo                  
Fair Value of Derivative Instruments
December 31, 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 $46,431  $389  $-  $46,820  $(25,649) $21,171 
Long-term Risk Management Assets  20,948   -   -   20,948   (4,000)  16,948 
Total Assets  67,379   389   -   67,768   (29,649)  38,119 
                    
Current Risk Management Liabilities  37,010   313   -   37,323   (28,431)  8,892 
Long-term Risk Management Liabilities  14,452   -   -   14,452   (4,211)  10,241 
Total Liabilities  51,462   313   -   51,775   (32,642)  19,133 
                    
Total MTM Derivative Contract Net                  
 Assets (Liabilities) $15,917  $76  $-  $15,993  $2,993  $18,986 

157


I&M                  
Fair Value of Derivative Instruments
March 31, 2014
                    
   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 $26,273  $152  $-  $26,425  $(13,867) $12,558 
Long-term Risk Management Assets  11,737   -   -   11,737   (2,232)  9,505 
Total Assets  38,010   152   -   38,162   (16,099)  22,063 
                    
Current Risk Management Liabilities  18,614   61   -   18,675   (14,541)  4,134 
Long-term Risk Management Liabilities  7,839   -   -   7,839   (2,461)  5,378 
Total Liabilities  26,453   61   -   26,514   (17,002)  9,512 
                    
Total MTM Derivative Contract Net                  
 Assets (Liabilities) $11,557  $91  $-  $11,648  $903  $12,551 
                    
I&M                  
Fair Value of Derivative Instruments
December 31, 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 $33,229  $234  $-  $33,463  $(18,075) $15,388 
Long-term Risk Management Assets  14,208   -   -   14,208   (2,713)  11,495 
Total Assets  47,437   234   -   47,671   (20,788)  26,883 
                    
Current Risk Management Liabilities  26,779   212   -   26,991   (19,962)  7,029 
Long-term Risk Management Liabilities  9,802   -   -   9,802   (2,856)  6,946 
Total Liabilities  36,581   212   -   36,793   (22,818)  13,975 
                    
Total MTM Derivative Contract Net                  
 Assets (Liabilities) $10,856  $22  $-  $10,878  $2,030  $12,908 

158


OPCo                  
Fair Value of Derivative Instruments
March 31, 2014
                    
   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 $4,066  $-  $-  $4,066  $(86) $3,980 
Long-term Risk Management Assets  -   -   -   -   -   - 
Total Assets  4,066   -   -   4,066   (86)  3,980 
                    
Current Risk Management Liabilities  83   -   -   83   (83)  - 
Long-term Risk Management Liabilities  -   -   -   -   -   - 
Total Liabilities  83   -   -   83   (83)  - 
                    
Total MTM Derivative Contract Net                  
 Assets (Liabilities) $3,983  $-  $-  $3,983  $(3) $3,980 
                    
OPCo                  
Fair Value of Derivative Instruments
December 31, 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 $3,269  $162  $-  $3,431  $(349) $3,082 
Long-term Risk Management Assets  -   -   -   -   -   - 
Total Assets  3,269   162   -   3,431   (349)  3,082 
                    
Current Risk Management Liabilities  349   -   -   349   (349)  - 
Long-term Risk Management Liabilities  -   -   -   -   -   - 
Total Liabilities  349   -   -   349   (349)  - 
                    
Total MTM Derivative Contract Net                  
 Assets (Liabilities) $2,920  $162  $-  $3,082  $-  $3,082 

159


PSO                  
Fair Value of Derivative Instruments
March 31, 2014
                    
   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 $1,403  $-  $-  $1,403  $(54) $1,349 
Long-term Risk Management Assets  -   -   -   -   -   - 
Total Assets  1,403   -   -   1,403   (54)  1,349 
                    
Current Risk Management Liabilities  136   -   -   136   (53)  83 
Long-term Risk Management Liabilities  -   -   -   -   -   - 
Total Liabilities  136   -   -   136   (53)  83 
                    
Total MTM Derivative Contract Net                  
 Assets (Liabilities) $1,267  $-  $-  $1,267  $(1) $1,266 
                    
PSO                  
Fair Value of Derivative Instruments
December 31, 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 $1,078  $84  $-  $1,162  $5  $1,167 
Long-term Risk Management Assets  -   -   -   -   -   - 
Total Assets  1,078   84   -   1,162   5   1,167 
                    
Current Risk Management Liabilities  81   -   -   81   4   85 
Long-term Risk Management Liabilities  -   -   -   -   -   - 
Total Liabilities  81   -   -   81   4   85 
                    
Total MTM Derivative Contract Net                  
 Assets (Liabilities) $997  $84  $-  $1,081  $1  $1,082 

160


SWEPCo                  
Fair Value of Derivative Instruments
March 31, 2014
                    
  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 $2,080  $-  $-  $2,080  $(173) $1,907 
Long-term Risk Management Assets  -   -   -   -   -   - 
Total Assets  2,080   -   -   2,080   (173)  1,907 
                   
Current Risk Management Liabilities  171   -   -   171   (171)  - 
Long-term Risk Management Liabilities  -   -   -   -   -   - 
Total Liabilities  171   -   -   171   (171)  - 
                   
Total MTM Derivative Contract Net                  
 Assets (Liabilities) $1,909  $-  $-  $1,909  $(2) $1,907 
                   
SWEPCo                  
Fair Value of Derivative Instruments
December 31, 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 $1,233  $97  $-  $1,330  $(151) $1,179 
Long-term Risk Management Assets  -   -   -   -   -   - 
Total Assets  1,233   97   -   1,330   (151)  1,179 
                   
Current Risk Management Liabilities  154   -   -   154   (154)  - 
Long-term Risk Management Liabilities  -   -   -   -   -   - 
Total Liabilities  154   -   -   154   (154)  - 
                   
Total MTM Derivative Contract Net                  
 Assets (Liabilities) $1,079  $97  $-  $1,176  $3  $1,179 
APCo

Fair Value of Derivative Instruments
June 30, 2014
  
Risk
Management
Contracts
 Hedging Contracts 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) 
Interest Rate
and Foreign
Currency (a)
   
  (in thousands)
Current Risk Management Assets $38,369
 $—
 $—
 $38,369
 $(13,550) $24,819
Long-term Risk Management Assets 10,305
 —
 —
 10,305
 (2,195) 8,110
Total Assets 48,674
 —
 —
 48,674
 (15,745) 32,929
             
Current Risk Management Liabilities 16,948
 —
 —
 16,948
 (12,722) 4,226
Long-term Risk Management Liabilities 5,570
 —
 —
 5,570
 (1,804) 3,766
Total Liabilities 22,518
 —
 —
 22,518
 (14,526) 7,992
             
Total MTM Derivative Contract Net Assets (Liabilities) $26,156
 $—
 $—
 $26,156
 $(1,219) $24,937

APCo

Fair Value of Derivative Instruments
December 31, 2013
  
Risk
Management
Contracts
 Hedging Contracts 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) 
Interest Rate
and Foreign
Currency (a)
   
  (in thousands)
Current Risk Management Assets $46,431
 $389
 $—
 $46,820
 $(25,649) $21,171
Long-term Risk Management Assets 20,948
 —
 —
 20,948
 (4,000) 16,948
Total Assets 67,379
 389
 —
 67,768
 (29,649) 38,119
             
Current Risk Management Liabilities 37,010
 313
 —
 37,323
 (28,431) 8,892
Long-term Risk Management Liabilities 14,452
 —
 —
 14,452
 (4,211) 10,241
Total Liabilities 51,462
 313
 —
 51,775
 (32,642) 19,133
             
Total MTM Derivative Contract Net Assets (Liabilities) $15,917
 $76
 $—
 $15,993
 $2,993
 $18,986

(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.


208


I&M

Fair Value of Derivative Instruments
June 30, 2014
161
  
Risk
Management
Contracts
 Hedging Contracts 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) 
Interest Rate
and Foreign
Currency (a)
   
  (in thousands)
Current Risk Management Assets $27,932
 $—
 $—
 $27,932
 $(10,043) $17,889
Long-term Risk Management Assets 6,894
 —
 —
 6,894
 (1,487) 5,407
Total Assets 34,826
 —
 —
 34,826
 (11,530) 23,296
             
Current Risk Management Liabilities 13,222
 —
 —
 13,222
 (9,745) 3,477
Long-term Risk Management Liabilities 3,778
 —
 —
 3,778
 (1,224) 2,554
Total Liabilities 17,000
 —
 —
 17,000
 (10,969) 6,031
             
Total MTM Derivative Contract Net Assets (Liabilities) $17,826
 $—
 $—
 $17,826
 $(561) $17,265

I&M

Fair Value of Derivative Instruments
December 31, 2013
  
Risk
Management
Contracts
 Hedging Contracts 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) 
Interest Rate
and Foreign
Currency (a)
   
  (in thousands)
Current Risk Management Assets $33,229
 $234
 $—
 $33,463
 $(18,075) $15,388
Long-term Risk Management Assets 14,208
 —
 —
 14,208
 (2,713) 11,495
Total Assets 47,437
 234
 —
 47,671
 (20,788) 26,883
             
Current Risk Management Liabilities 26,779
 212
 —
 26,991
 (19,962) 7,029
Long-term Risk Management Liabilities 9,802
 —
 —
 9,802
 (2,856) 6,946
Total Liabilities 36,581
 212
 —
 36,793
 (22,818) 13,975
             
Total MTM Derivative Contract Net Assets (Liabilities) $10,856
 $22
 $—
 $10,878
 $2,030
 $12,908

(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.


209


OPCo

Fair Value of Derivative Instruments
June 30, 2014
  
Risk
Management
Contracts
 Hedging Contracts 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) 
Interest Rate
and Foreign
Currency (a)
   
  (in thousands)
Current Risk Management Assets $9,430
 $—
 $—
 $9,430
 $(131) $9,299
Long-term Risk Management Assets 14
 —
 —
 14
 (14) —
Total Assets 9,444
 —
 —
 9,444
 (145) 9,299
             
Current Risk Management Liabilities —
 —
 —
 —
 —
 —
Long-term Risk Management Liabilities —
 —
 —
 —
 —
 —
Total Liabilities —
 —
 —
 —
 —
 —
             
Total MTM Derivative Contract Net Assets (Liabilities) $9,444
 $—
 $—
 $9,444
 $(145) $9,299

OPCo

Fair Value of Derivative Instruments
December 31, 2013
  
Risk
Management
Contracts
 Hedging Contracts 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) 
Interest Rate
and Foreign
Currency (a)
   
  (in thousands)
Current Risk Management Assets $3,269
 $162
 $—
 $3,431
 $(349) $3,082
Long-term Risk Management Assets —
 —
 —
 —
 —
 —
Total Assets 3,269
 162
 —
 3,431
 (349) 3,082
             
Current Risk Management Liabilities 349
 —
 —
 349
 (349) —
Long-term Risk Management Liabilities —
 —
 —
 —
 —
 —
Total Liabilities 349
 —
 —
 349
 (349) —
             
Total MTM Derivative Contract Net Assets (Liabilities) $2,920
 $162
 $—
 $3,082
 $—
 $3,082

(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.


210


PSO

Fair Value of Derivative Instruments
June 30, 2014
  
Risk
Management
Contracts
 Hedging Contracts 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) 
Interest Rate
and Foreign
Currency (a)
   
  (in thousands)
Current Risk Management Assets $509
 $—
 $—
 $509
 $13
 $522
Long-term Risk Management Assets 8
 —
 —
 8
 (8) —
Total Assets 517
 —
 —
 517
 5
 522
             
Current Risk Management Liabilities 25
 —
 —
 25
 77
 102
Long-term Risk Management Liabilities —
 —
 —
 —
 —
 —
Total Liabilities 25
 —
 —
 25
 77
 102
             
Total MTM Derivative Contract Net Assets (Liabilities) $492
 $—
 $—
 $492
 $(72) $420

PSO

Fair Value of Derivative Instruments
December 31, 2013
  
Risk
Management
Contracts
 Hedging Contracts 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) 
Interest Rate
and Foreign
Currency (a)
   
  (in thousands)
Current Risk Management Assets $1,078
 $84
 $—
 $1,162
 $5
 $1,167
Long-term Risk Management Assets —
 —
 —
 —
 —
 —
Total Assets 1,078
 84
 —
 1,162
 5
 1,167
             
Current Risk Management Liabilities 81
 —
 —
 81
 4
 85
Long-term Risk Management Liabilities —
 —
 —
 —
 —
 —
Total Liabilities 81
 —
 —
 81
 4
 85
             
Total MTM Derivative Contract Net Assets (Liabilities) $997
 $84
 $—
 $1,081
 $1
 $1,082

(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.


211


SWEPCo

Fair Value of Derivative Instruments
June 30, 2014
  
Risk
Management
Contracts
 Hedging Contracts 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) 
Interest Rate
and Foreign
Currency (a)
   
  (in thousands)
Current Risk Management Assets $596
 $—
 $—
 $596
 $(90) $506
Long-term Risk Management Assets 9
 —
 —
 9
 (9) —
Total Assets 605
 —
 —
 605
 (99) 506
             
Current Risk Management Liabilities 33
 —
 —
 33
 (16) 17
Long-term Risk Management Liabilities —
 —
 —
 —
 —
 —
Total Liabilities 33
 —
 —
 33
 (16) 17
             
Total MTM Derivative Contract Net Assets (Liabilities) $572
 $—
 $—
 $572
 $(83) $489

SWEPCo

Fair Value of Derivative Instruments
December 31, 2013
  
Risk
Management
Contracts
 Hedging Contracts 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) 
Interest Rate
and Foreign
Currency (a)
   
  (in thousands)
Current Risk Management Assets $1,233
 $97
 $—
 $1,330
 $(151) $1,179
Long-term Risk Management Assets —
 —
 —
 —
 —
 —
Total Assets 1,233
 97
 —
 1,330
 (151) 1,179
             
Current Risk Management Liabilities 154
 —
 —
 154
 (154) —
Long-term Risk Management Liabilities —
 —
 —
 —
 —
 —
Total Liabilities 154
 —
 —
 154
 (154) —
             
Total MTM Derivative Contract Net Assets (Liabilities) $1,079
 $97
 $—
 $1,176
 $3
 $1,179

(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.


212


The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and six months ended March 31,June 30, 2014 and 2013:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended March 31, 2014
 
Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo
    (in thousands)
Electric Generation, Transmission and               
 Distribution Revenues $ 4,847  $ 6,156  $ -  $ 64  $ 23 
Sales to AEP Affiliates   -    (221)   -    221    - 
Regulatory Assets (a)   4    -    -    2    3 
Regulatory Liabilities (a)   32,332    18,317    35,099    480    1,330 
Total Gain on Risk Management               
 Contracts $ 37,183  $ 24,252  $ 35,099  $ 767  $ 1,356 
                  
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended March 31, 2013
 
Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo
    (in thousands)
Electric Generation, Transmission and               
 Distribution Revenues $ 679  $ 4,947  $ 1,714  $ 47  $ 28 
Regulatory Assets (a)   -    486    (1,205)   2,010    271 
Regulatory Liabilities (a)   (466)   (5,182)   -    1    96 
Total Gain on Risk Management               
 Contracts $ 213  $ 251  $ 509  $ 2,058  $ 395 
                  
(a)   Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2014
Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo
  (in thousands)
Electric Generation, Transmission and Distribution Revenues $1,184
 $1,323
 $56
 $63
 $(79)
Sales to AEP Affiliates —
 (300) —
 300
 —
Regulatory Assets (a) —
 —
 —
 (12) (16)
Regulatory Liabilities (a) 13,718
 8,793
 6,404
 (669) (1,019)
Total Gain (Loss) on Risk Management Contracts $14,902
 $9,816
 $6,460
 $(318) $(1,114)

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
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 Six Months Ended June 30, 2014
Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo
  (in thousands)
Electric Generation, Transmission and Distribution Revenues $6,031
 $7,479
 $56
 $127
 $(56)
Sales to AEP Affiliates —
 (521) —
 521
 —
Regulatory Assets (a) 4
 —
 —
 (10) (13)
Regulatory Liabilities (a) 46,050
 27,110
 41,503
 (189) 311
Total Gain on Risk Management Contracts $52,085
 $34,068
 $41,559
 $449
 $242

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
Regulatory Assets (a) —
 (1,099) (5,697) 2,202
 (102)
Regulatory Liabilities (a) (210) (6,062) 3,360
 —
 135
Total Gain on Risk Management Contracts $663
 $683
 $1,196
 $2,418
 $363
(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.


213


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 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.

162
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 March 31,June 30, 2014 and 2013, 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 March 31,June 30, 2014, APCo and I&M designated power, coal and natural gas derivatives as cash flow hedges. During the three and six months ended June 30, 2013, 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 March 31,June 30, 2013, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014.


214


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 March 31,June 30, 2014 and 2013, I&M 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 March 31,June 30, 2014 and 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges.

During the three and six months ended March 31,June 30, 2014 and 2013, 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 March 31,June 30, 2014 and 2013, see Note 3.


215
163


Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31,June 30, 2014 and December 31, 2013 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
March 31, 2014
 
   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 $ 209  $ -  $ 75  $ -  $ 87  $ 3,343 
I&M   142    -    51    -    61    (15,566)
OPCo   -    -    -    -    -    6,631 
PSO   -    -    -    -    -    5,512 
SWEPCo   -    -    -    -    -    (12,736)
Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
June 30, 2014
  Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax
Company Commodity 
Interest Rate
and Foreign
Currency
 Commodity 
Interest Rate
and Foreign
Currency
 Commodity 
Interest Rate
and Foreign
Currency
  (in thousands)
APCo $—
 $—
 $—
 $—
 $—
 $3,596
I&M —
 —
 —
 —
 —
 (15,155)
OPCo —
 —
 —
 —
 —
 6,288
PSO —
 —
 —
 —
 —
 5,322
SWEPCo —
 —
 —
 —
 —
 (12,169)
  
Expected to be Reclassified to
Net Income During the Next
Twelve Months
  
Company Commodity 
Interest Rate
and Foreign
Currency
 
Maximum Term for
Exposure to
Variability of Future
Cash Flows
  (in thousands) (in months)
APCo $—
 $(431) 0
I&M —
 (1,283) 0
OPCo —
 1,372
 0
PSO —
 759
 0
SWEPCo —
 (2,267) 0

   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 $ 87  $ (682)   2 
I&M   61    (1,426)   2 
OPCo   -    1,372    - 
PSO   -    759    - 
SWEPCo   -    (2,267)   - 
Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 2013
  Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax
Company Commodity 
Interest Rate
and Foreign
Currency
 Commodity 
Interest Rate
and Foreign
Currency
 Commodity 
Interest Rate
and Foreign
Currency
  (in thousands)
APCo $363
 $—
 $287
 $—
 $94
 $3,090
I&M 216
 —
 194
 —
 46
 (15,976)
OPCo 162
 —
 —
 —
 105
 6,974
PSO 84
 —
 —
 —
 57
 5,701
SWEPCo 97
 —
 —
 —
 66
 (13,304)
  
Expected to be Reclassified to
Net Income During the Next
Twelve Months
Company Commodity 
Interest Rate
and Foreign
Currency
  (in thousands)
APCo $94
 $(806)
I&M 46
 (1,568)
OPCo 105
 1,363
PSO 57
 759
SWEPCo 66
 (2,267)

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 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 $ 363  $ -  $ 287  $ -  $ 94  $ 3,090 
I&M   216    -    194    -    46    (15,976)
OPCo   162    -    -    -    105    6,974 
PSO   84    -    -    -    57    5,701 
SWEPCo   97    -    -    -    66    (13,304)

   Expected to be Reclassified to 
   Net Income During the Next 
   Twelve Months 
     Interest Rate 
     and Foreign 
Company Commodity Currency 
   (in thousands) 
APCo $ 94  $ (806) 
I&M   46    (1,568) 
OPCo   105    1,363  
PSO   57    759  
SWEPCo   66    (2,267) 

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


216
164


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 March 31,June 30, 2014 and December 31, 2013:

  March 31, 2014
  Liabilities for Amount of Collateral the Amount
  Derivative Contracts Registrant Subsidiaries Attributable to
  with Credit Would Have Been RTO and ISO June 30, 2014
CompanyCompany Downgrade Triggers Required to Post Activities 
Liabilities for
Derivative Contracts
with Credit
Downgrade Triggers
 
Amount of Collateral the
Registrant Subsidiaries
Would Have Been
Required to Post
 
Amount
Attributable to
RTO and ISO
Activities
  (in thousands) (in thousands)
APCoAPCo $ 285  $ 5,254  $ 4,774  $140
 $3,096
 $3,023
I&MI&M   190    3,560    3,238  95
 2,096
 2,051
OPCoOPCo   78    -    -  —
 —
 —
PSOPSO   132    4,156    -  3
 10,137
 5,989
SWEPCoSWEPCo   167    145    -  3
 7,729
 7,585
  December 31, 2013
Company 
Liabilities for
Derivative Contracts
with Credit
Downgrade Triggers
 
Amount of Collateral the
Registrant Subsidiaries
Would Have Been
Required to Post
 
Amount
Attributable to
RTO and ISO
Activities
  (in thousands)
APCo $575
 $2,747
 $2,539
I&M 390
 1,863
 1,722
OPCo 349
 —
 —
PSO —
 2,930
 410
SWEPCo —
 713
 519

217

   December 31, 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 $ 575  $ 2,747  $ 2,539 
I&M   390    1,863    1,722 
OPCo   349    -    - 
PSO   -    2,930    410 
SWEPCo   -    713    519 


165
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 March 31,June 30, 2014 and December 31, 2013:

  March 31, 2014
  Liabilities for   Additional
  Contracts with Cross   Settlement
  Default Provisions   Liability if Cross
  Prior to Contractual Amount of Cash Default Provision June 30, 2014
CompanyCompany Netting Arrangements Collateral Posted is Triggered 
Liabilities for
Contracts with Cross
Default Provisions
Prior to Contractual
Netting Arrangements
 
Amount of Cash
Collateral Posted
 
Additional
Settlement
Liability if Cross
Default Provision
is Triggered
  (in thousands) (in thousands)
APCoAPCo $ 16,375  $ -  $ 12,865  $10,809
 $—
 $7,909
I&MI&M   11,107    -    8,726  7,328
 —
 5,362
OPCoOPCo   -    -    -  —
 —
 —
PSOPSO   -    -    -  14
 —
 14
SWEPCoSWEPCo   -    -    -  18
 —
 18
          
  December 31, 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 $ 19,648  $ -  $ 18,568 
I&M   13,326    -    12,594 
OPCo   -    -    - 
PSO   3    -    3 
SWEPCo   3    -    3 
  December 31, 2013
Company 
Liabilities for
Contracts with Cross
Default Provisions
Prior to Contractual
Netting Arrangements
 
Amount of Cash
Collateral Posted
 
Additional
Settlement
Liability if Cross
Default Provision
is Triggered
  (in thousands)
APCo $19,648
 $—
 $18,568
I&M 13,326
 —
 12,594
OPCo —
 —
 —
PSO 3
 —
 3
SWEPCo 3
 —
 3


218


9.  10.  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 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. The AEP System’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.

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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, Restricted Cash for Securitized Funding 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

219


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 March 31,June 30, 2014 and December 31, 2013 are summarized in the following table:

 March 31, 2014 December 31, 2013 June 30, 2014 December 31, 2013
Company Book Value Fair Value Book Value Fair Value Book Value Fair Value Book Value Fair Value
 (in thousands) (in thousands)
APCo $ 4,194,516  $ 4,730,819  $ 4,194,357  $ 4,587,079  $3,992,617
 $4,624,573
 $4,194,357
 $4,587,079
I&M   2,012,844   2,203,640    2,039,016   2,174,891  1,979,041
 2,193,580
 2,039,016
 2,174,891
OPCo   2,510,285   2,869,364    2,735,175   3,007,191  2,370,952
 2,760,808
 2,735,175
 3,007,191
PSO   1,049,793   1,200,741    999,810   1,111,149  1,041,075
 1,207,009
 999,810
 1,111,149
SWEPCo   2,041,796   2,277,262    2,043,332   2,214,730  2,041,885
 2,330,329
 2,043,332
 2,214,730

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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.

220



The following is a summary of nuclear trust fund investments as of March 31,June 30, 2014 and December 31, 2013:

  March 31, 2014 December 31, 2013
  Estimated Gross Other-Than- Estimated Gross Other-Than-
 FairUnrealizedTemporaryFairUnrealizedTemporaryJune 30, 2014 December 31, 2013
 ValueGainsImpairmentsValueGainsImpairments
Estimated Fair
Value
 
Gross Unrealized
Gains
 
Other-Than-Temporary
Impairments
 
Estimated Fair
Value
 
Gross Unrealized
Gains
 Other-Than-Temporary Impairments
  (in thousands)(in thousands)
Cash and Cash EquivalentsCash and Cash Equivalents $ 12,439  $ -  $ -  $ 18,804  $ -  $ - $14,847
 $—
 $—
 $18,804
 $—
 $—
Fixed Income Securities:Fixed Income Securities:             
  
  
  
  
  
United States Government  606,228   31,666   (3,621)  608,875   26,114   (3,824)
Corporate Debt  42,727   3,223   (1,097)  36,782   2,450   (1,123)
State and Local Government   280,612    972    (345)   254,638    748    (370)
  Subtotal Fixed Income Securities  929,567   35,861   (5,063)  900,295   29,312   (5,317)
United States Government579,840
 36,602
 (26,358) 608,875
 26,114
 (3,824)
Corporate Debt46,567
 3,791
 (1,068) 36,782
 2,450
 (1,123)
State and Local Government309,233
 889
 (590) 254,638
 748
 (370)
Subtotal Fixed Income Securities935,640
 41,282
 (28,016) 900,295
 29,312
 (5,317)
Equity Securities - DomesticEquity Securities - Domestic   1,020,145    513,803    (79,563)   1,012,511    505,538    (81,677)1,068,019
 557,150
 (79,089) 1,012,511
 505,538
 (81,677)
Spent Nuclear Fuel and            
Decommissioning Trusts $ 1,962,151  $ 549,664  $ (84,626) $ 1,931,610  $ 534,850  $ (86,994)
Spent Nuclear Fuel and Decommissioning Trusts$2,018,506
 $598,432
 $(107,105) $1,931,610
 $534,850
 $(86,994)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended March 31,June 30, 2014 and 2013:

Three Months Ended March 31, Three Months Ended June 30, Six Months Ended June 30,
2014  2013  2014 2013 2014 2013
(in thousands) (in thousands)
Proceeds from Investment Sales$ 147,700  $ 167,670  $334,834
 $218,272
 $482,534
 $385,942
Purchases of Investments  164,511    184,299  344,324
 227,470
 508,835
 411,769
Gross Realized Gains on Investment Sales  8,141    3,323  9,077
 8,575
 17,218
 11,898
Gross Realized Losses on Investment Sales  874    2,315  7,834
 7,397
 8,708
 9,712

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The adjusted cost of fixed income securities was $894 million and $872 million as of March 31,June 30, 2014 and December 31, 2013, respectively.  The adjusted cost of equity securities was $506$511 million and $506 million as of March 31,June 30, 2014 and December 31, 2013, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31,June 30, 2014 was as follows:

Fair Value of
Fixed Income
Securities
(in thousands)
Within 1 year$ 82,190 
1 year – 5 years 386,173 
5 years – 10 years 193,018 
After 10 years 268,186 
Total$ 929,567 
 Fair Value of Fixed Income Securities
 (in thousands)
Within 1 year$38,967
1 year – 5 years414,273
5 years – 10 years207,156
After 10 years275,244
Total$935,640


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169


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 March 31,June 30, 2014 and December 31, 2013.  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
March 31, 2014
           
  Level 1 Level 2 Level 3 Other Total
Assets:(in thousands)
                
Restricted Cash for Securitized Funding (a)$ 13,536  $ -  $ -  $ 36  $ 13,572 
                
Risk Management Assets              
Risk Management Commodity Contracts (b) (c)  393    37,854    10,508    (18,979)   29,776 
Cash Flow Hedges:              
 Commodity Hedges (b)  -    224    -    (15)   209 
Total Risk Management Assets  393    38,078    10,508    (18,994)   29,985 
                
Total Assets:$ 13,929  $ 38,078  $ 10,508  $ (18,958) $ 43,557 
                
Liabilities:              
                
Risk Management Liabilities              
Risk Management Commodity Contracts (b) (c)$ 306  $ 29,386  $ 3,107  $ (20,309) $ 12,490 
Cash Flow Hedges:              
 Commodity Hedges (b)  -    90    -    (15)   75 
Total Risk Management Liabilities$ 306  $ 29,476  $ 3,107  $ (20,324) $ 12,565 
APCo

APCo              
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
           
  Level 1 Level 2 Level 3 Other Total
Assets:(in thousands)
                
Restricted Cash for Securitized Funding (a)$ 2,714  $ -  $ -  $ 36  $ 2,750 
                
Risk Management Assets              
Risk Management Commodity Contracts (b) (c)  827    54,448    12,097    (29,616)   37,756 
Cash Flow Hedges:              
 Commodity Hedges (b)  -    389    -    (26)   363 
Total Risk Management Assets  827    54,837    12,097    (29,642)   38,119 
                
Total Assets$ 3,541  $ 54,837  $ 12,097  $ (29,606) $ 40,869 
                
Liabilities:              
                
Risk Management Liabilities              
Risk Management Commodity Contracts (b) (c)$ 700  $ 49,220  $ 1,535  $ (32,609) $ 18,846 
Cash Flow Hedges:              
 Commodity Hedges (b)  -    313    -    (26)   287 
Total Risk Management Liabilities$ 700  $ 49,533  $ 1,535  $ (32,635) $ 19,133 
Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2014
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I&M              
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2014
            
   Level 1 Level 2 Level 3 Other Total
Assets:(in thousands)
                 
Risk Management Assets              
Risk Management Commodity Contracts (b) (c)$ 267  $ 28,746  $ 6,945  $ (14,037) $ 21,921 
Cash Flow Hedges:              
 Commodity Hedges (b)  -    152    -    (10)   142 
Total Risk Management Assets  267    28,898    6,945    (14,047)   22,063 
                 
Spent Nuclear Fuel and Decommissioning Trusts              
Cash and Cash Equivalents (d)  3,576    -    -    8,863    12,439 
Fixed Income Securities:              
 United States Government  -    606,228    -    -    606,228 
 Corporate Debt  -    42,727    -    -    42,727 
 State and Local Government  -    280,612    -    -    280,612 
  Subtotal Fixed Income Securities  -    929,567    -    -    929,567 
Equity Securities - Domestic (e)  1,020,145    -    -    -    1,020,145 
Total Spent Nuclear Fuel and Decommissioning Trusts  1,023,721    929,567    -    8,863    1,962,151 
                 
Total Assets$ 1,023,988  $ 958,465  $ 6,945  $ (5,184) $ 1,984,214 
                 
Liabilities:              
                 
Risk Management Liabilities              
Risk Management Commodity Contracts (b) (c)$ 208  $ 22,089  $ 2,104  $ (14,940) $ 9,461 
Cash Flow Hedges:              
 Commodity Hedges (b)  -    61    -    (10)   51 
Total Risk Management Liabilities$ 208  $ 22,150  $ 2,104  $ (14,950) $ 9,512 
  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands)
           
Restricted Cash for Securitized Funding (a) $20,709
 $—
 $—
 $52
 $20,761
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (b) (c) 254
 26,923
 20,307
 (14,555) 32,929
           
Total Assets: $20,963
 $26,923
 $20,307
 $(14,503) $53,690
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (b) (c) $197
 $19,218
 $1,913
 $(13,336) $7,992

I&M              
  Assets and Liabilities Measured at Fair Value on a Recurring Basis
  December 31, 2013
            
   Level 1 Level 2 Level 3 Other Total
Assets:(in thousands)
                 
Risk Management Assets              
Risk Management Commodity Contracts (b) (c)$ 561  $ 38,667  $ 8,205  $ (20,766) $ 26,667 
Cash Flow Hedges:              
 Commodity Hedges (b)  -    234    -    (18)   216 
Total Risk Management Assets  561    38,901    8,205    (20,784)   26,883 
                 
Spent Nuclear Fuel and Decommissioning Trusts              
Cash and Cash Equivalents (d)  8,082    -    -    10,722    18,804 
Fixed Income Securities:              
 United States Government  -    608,875    -    -    608,875 
 Corporate Debt  -    36,782    -    -    36,782 
 State and Local Government  -    254,638    -    -    254,638 
  Subtotal Fixed Income Securities  -    900,295    -    -    900,295 
Equity Securities - Domestic (e)  1,012,511    -    -    -    1,012,511 
Total Spent Nuclear Fuel and Decommissioning Trusts  1,020,593    900,295    -    10,722    1,931,610 
                 
Total Assets$ 1,021,154  $ 939,196  $ 8,205  $ (10,062) $ 1,958,493 
                 
Liabilities:              
                 
Risk Management Liabilities              
Risk Management Commodity Contracts (b) (c)$ 475  $ 35,061  $ 1,041  $ (22,796) $ 13,781 
Cash Flow Hedges:              
 Commodity Hedges (b)  -    212    -    (18)   194 
Total Risk Management Liabilities$ 475  $ 35,273  $ 1,041  $ (22,814) $ 13,975 

171


OPCo              
 Assets and Liabilities Measured at Fair Value on a Recurring Basis
 March 31, 2014
                
  Level 1 Level 2 Level 3 Other Total
Assets:(in thousands)
                
Restricted Cash for Securitized Funding (a)$ 32,054  $ -  $ -  $ 12  $ 32,066 
                
Risk Management Assets              
Risk Management Commodity Contracts (b) (c)  -    76    3,990    (86)   3,980 
                
Total Assets$ 32,054  $ 76  $ 3,990  $ (74) $ 36,046 
                
Liabilities:              
                
Risk Management Liabilities              
Risk Management Commodity Contracts (b) (c)$ -  $ 5  $ 78  $ (83) $ - 
APCo

OPCo              
 Assets and Liabilities Measured at Fair Value on a Recurring Basis
 December 31, 2013
           
  Level 1 Level 2 Level 3 Other Total
Assets:(in thousands)
                
Restricted Cash for Securitized Funding (a)$ 19,387  $ -  $ -  $ 12  $ 19,399 
                
Risk Management Assets              
Risk Management Commodity Contracts (b) (c)  -    -    3,269    (349)   2,920 
Cash Flow Hedges:              
 Commodity Hedges (b)  -    162    -    -    162 
Total Risk Management Assets  -    162    3,269    (349)   3,082 
                
Total Assets$ 19,387  $ 162  $ 3,269  $ (337) $ 22,481 
                
Liabilities:              
                
Risk Management Liabilities              
Risk Management Commodity Contracts (b) (c)$ -  $ -  $ 349  $ (349) $ - 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands)
           
Restricted Cash for Securitized Funding (a) $2,714
 $—
 $—
 $36
 $2,750
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (b) (c) 827
 54,448
 12,097
 (29,616) 37,756
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (b) —
 389
 —
 (26) 363
Total Risk Management Assets 827
 54,837
 12,097
 (29,642) 38,119
           
Total Assets: $3,541
 $54,837
 $12,097
 $(29,606) $40,869
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (b) (c) $700
 $49,220
 $1,535
 $(32,609) $18,846
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (b) —
 313
 —
 (26) 287
Total Risk Management Liabilities $700
 $49,533
 $1,535
 $(32,635) $19,133


222
172



PSO              
 Assets and Liabilities Measured at Fair Value on a Recurring Basis
 March 31, 2014
           
  Level 1 Level 2 Level 3 Other Total
Assets:(in thousands)
                
Risk Management Assets              
Risk Management Commodity Contracts (b) (c)$ -  $ 922  $ 481  $ (54) $ 1,349 
                
Liabilities:              
                
Risk Management Liabilities              
Risk Management Commodity Contracts (b) (c)$ -  $ 4  $ 132  $ (53) $ 83 
I&M

PSO              
 Assets and Liabilities Measured at Fair Value on a Recurring Basis
 December 31, 2013
           
  Level 1 Level 2 Level 3 Other Total
Assets:(in thousands)
                
Risk Management Assets              
Risk Management Commodity Contracts (b) (c)$ -  $ 1,078  $ -  $ 5  $ 1,083 
Cash Flow Hedges:              
 Commodity Hedges (b)  -    84    -    -    84 
Total Risk Management Assets$ -  $ 1,162  $ -  $ 5  $ 1,167 
                
Liabilities:              
                
Risk Management Liabilities              
Risk Management Commodity Contracts (b) (c)$ -  $ 81  $ -  $ 4  $ 85 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2014
  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (b) (c) $171
 $19,628
 $14,220
 $(10,723) $23,296
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (d) 3,635
 —
 —
 11,212
 14,847
Fixed Income Securities:  
  
  
  
  
United States Government —
 579,840
 —
 —
 579,840
Corporate Debt —
 46,567
 —
 —
 46,567
State and Local Government —
 309,233
 —
 —
 309,233
Subtotal Fixed Income Securities —
 935,640
 —
 —
 935,640
Equity Securities - Domestic (e) 1,068,019
 —
 —
 —
 1,068,019
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,071,654
 935,640
 —
 11,212
 2,018,506
           
Total Assets $1,071,825
 $955,268
 $14,220
 $489
 $2,041,802
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (b) (c) $133
 $14,763
 $1,297
 $(10,162) $6,031


223
173



SWEPCo              
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2014
          
  Level 1 Level 2 Level 3 Other Total
Assets:(in thousands)
                
Cash and Cash Equivalents (a)$ 15,537  $ -  $ -  $ 2,458  $ 17,995 
                
Risk Management Assets              
Risk Management Commodity Contracts (b) (c)  -    1,471    609    (173)   1,907 
                
Total Assets$ 15,537  $ 1,471  $ 609  $ 2,285  $ 19,902 
                
Liabilities:              
                
Risk Management Liabilities              
Risk Management Commodity Contracts (b) (c)$ -  $ 4  $ 167  $ (171) $ - 
I&M

SWEPCo              
 Assets and Liabilities Measured at Fair Value on a Recurring Basis
 December 31, 2013
           
  Level 1 Level 2 Level 3 Other Total
Assets:(in thousands)
                
Cash and Cash Equivalents (a)$ 15,871  $ -  $ -  $ 1,370  $ 17,241 
                
Risk Management Assets              
Risk Management Commodity Contracts (b) (c)  -    1,233    -    (151)   1,082 
Cash Flow Hedges:              
 Commodity Hedges (b)  -    97    -    -    97 
Total Risk Management Assets  -    1,330    -    (151)   1,179 
                
Total Assets$ 15,871  $ 1,330  $ -  $ 1,219  $ 18,420 
                
Liabilities:              
                
Risk Management Liabilities              
Risk Management Commodity Contracts (b) (c)$ -  $ 154  $ -  $ (154) $ - 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (b) (c) $561
 $38,667
 $8,205
 $(20,766) $26,667
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (b) —
 234
 —
 (18) 216
Total Risk Management Assets 561
 38,901
 8,205
 (20,784) 26,883
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (d) 8,082
 —
 —
 10,722
 18,804
Fixed Income Securities:  
  
  
  
 

United States Government —
 608,875
 —
 —
 608,875
Corporate Debt —
 36,782
 —
 —
 36,782
State and Local Government —
 254,638
 —
 —
 254,638
Subtotal Fixed Income Securities —
 900,295
 —
 —
 900,295
Equity Securities - Domestic (e) 1,012,511
 —
 —
 —
 1,012,511
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,020,593
 900,295
 —
 10,722
 1,931,610
           
Total Assets $1,021,154
 $939,196
 $8,205
 $(10,062) $1,958,493
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (b) (c) $475
 $35,061
 $1,041
 $(22,796) $13,781
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (b) —
 212
 —
 (18) 194
Total Risk Management Liabilities $475
 $35,273
 $1,041
 $(22,814) $13,975



224


OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2014
  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands)
           
Restricted Cash for Securitized Funding (a) $43,003
 $—
 $—
 $31
 $43,034
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (b) (c) —
 144
 9,300
 (145) 9,299
           
Total Assets $43,003
 $144
 $9,300
 $(114) $52,333

As of June 30, 2014, OPCo had no liabilities measured at fair value on a recurring basis.

OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands)
           
Restricted Cash for Securitized Funding (a) $19,387
 $—
 $—
 $12
 $19,399
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (b) (c) —
 —
 3,269
 (349) 2,920
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (b) —
 162
 —
 —
 162
Total Risk Management Assets —
 162
 3,269
 (349) 3,082
           
Total Assets $19,387
 $162
 $3,269
 $(337) $22,481
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (b) (c) $—
 $—
 $349
 $(349) $—


225


PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2014
  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (b) (c) $9
 $508
 $—
 $5
 $522
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (b) (c) $5
 $17
 $3
 $77
 $102

PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (b) (c) $—
 $1,078
 $—
 $5
 $1,083
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (b) —
 84
 —
 —
 84
Total Risk Management Assets $—
 $1,162
 $—
 $5
 $1,167
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (b) (c) $—
 $81
 $—
 $4
 $85


226


SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2014
  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands)
           
Cash and Cash Equivalents (a) $14,622
 $—
 $—
 $2,349
 $16,971
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (b) (c) 12
 593
 —
 (99) 506
           
Total Assets $14,634
 $593
 $—
 $2,250
 $17,477
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (b) (c) $7
 $23
 $3
 $(16) $17

SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands)
           
Cash and Cash Equivalents (a) $15,871
 $—
 $—
 $1,370
 $17,241
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (b) (c) —
 1,233
 —
 (151) 1,082
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (b) —
 97
 —
 —
 97
Total Risk Management Assets —
 1,330
 —
 (151)
1,179
           
Total Assets $15,871
 $1,330
 $—
 $1,219
 $18,420
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (b) (c) $—
 $154
 $—
 $(154) $—

(a)Amounts in “Other”"Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investment in money market funds.
(b)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”.Hedging.”
(c)Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
(d)Amounts in “Other” column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(e)Amounts represent publicly traded equity securities and equity-based mutual funds.

There were no transfers between Level 1 and Level 2 during the three and six months ended March 31,June 30, 2014 and 2013.

227
174



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:hierarchy for the Registrant Subsidiaries:
Three Months Ended June 30, 2014 APCo I&M OPCo PSO SWEPCo
  (in thousands)
Balance as of March 31, 2014 $7,401
 $4,842
 $3,912
 $349
 $442
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (4,046) (2,554) (4,236) (349) (442)
Purchases, Issuances and Settlements (c) (32) (35) 347
 —
 —
Transfers into Level 3 (d) (e) 182
 124
 —
 —
 —
Transfers out of Level 3 (e) (f) 3
 2
 —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,886
 10,544
 9,277
 (3) (3)
Balance as of June 30, 2014 $18,394
 $12,923
 $9,300
 $(3) $(3)

Three Months Ended March 31, 2014 APCo I&M OPCo PSO SWEPCo
  (in thousands)
Balance as of December 31, 2013 $ 10,562  $ 7,164  $ 2,920  $ -  $ - 
Realized Gain (Loss) Included in Net Income               
 (or Changes in Net Assets) (a) (b)   29,162    18,219    30,963    -    - 
Unrealized Gain (Loss) Included in Net               
 Income (or Changes in Net Assets) Relating               
 to Assets Still Held at the Reporting Date (a)   -    -    -    -    - 
Realized and Unrealized Gains (Losses)               
 Included in Other Comprehensive Income   -    -    -    -    - 
Purchases, Issuances and Settlements (c)   (31,781)   (19,995)   (34,036)   -    - 
Transfers into Level 3 (d) (e)   (3,825)   (2,594)   -    -    - 
Transfers out of Level 3 (e) (f)   (6)   (4)   -    -    - 
Changes in Fair Value Allocated to Regulated               
 Jurisdictions (g)   3,289    2,052    4,065    349    442 
Balance as of March 31, 2014 $ 7,401  $ 4,842  $ 3,912  $ 349  $ 442 
Three Months Ended June 30, 2013 APCo I&M OPCo PSO SWEPCo
  (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
 —
 —
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 March 31, 2013 APCo I&M OPCo PSO SWEPCo
  (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)   (1,456)   (1,005)   (2,055)   -    - 
Unrealized Gain (Loss) Included in Net               
 Income (or Changes in Net Assets) Relating               
 to Assets Still Held at the Reporting Date (a)   -    -    (1,988)   -    - 
Realized and Unrealized Gains (Losses)               
 Included in Other Comprehensive Income   -    -    -    -    - 
Purchases, Issuances and Settlements (c)   257    179    366    -    - 
Transfers into Level 3 (d) (e)   632    434    888    -    - 
Transfers out of Level 3 (e) (f)   (533)   (366)   (749)   -    - 
Changes in Fair Value Allocated to Regulated               
 Jurisdictions (g)   (1,123)   (732)   490    -    - 
Balance as of March 31, 2013 $ 8,756  $ 6,051  $ 12,381  $ -  $ - 
Six Months Ended June 30, 2014 APCo I&M OPCo PSO SWEPCo
  (in thousands)
Balance as of December 31, 2013 $10,562
 $7,164
 $2,920
 $—
 $—
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 29,132
 18,211
 30,768
 —
 —
Purchases, Issuances and Settlements (c) (31,790) (20,014) (33,688) —
 —
Transfers into Level 3 (d) (e) (3,643) (2,471) —
 —
 —
Transfers out of Level 3 (e) (f) (2) (2) —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,135
 10,035
 9,300
 (3) (3)
Balance as of June 30, 2014 $18,394
 $12,923
 $9,300
 $(3) $(3)


228


Six Months Ended June 30, 2013 APCo I&M OPCo PSO SWEPCo
  (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
 —
 —
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
 $—
 $—

(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.


229
175


The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions for the Registrant Subsidiaries as of March 31,June 30, 2014 and December 31, 2013:

Significant Unobservable Inputs
March 31, 2014
APCo                
  Fair Value Valuation Significant Forward Price Range
 Assets LiabilitiesTechniqueUnobservable Input (a) Low High
  (in thousands)          
Energy Contracts $ 6,454  $ 2,822  Discounted Cash Flow  Forward Market Price  $ 13.34  $ 59.60 
FTRs   4,054    285  Discounted Cash Flow  Forward Market Price    (5.05)   9.17 
Total $ 10,508  $ 3,107           
                 
Significant Unobservable Inputs
December 31, 2013
APCo                
  Fair Value Valuation Significant Forward Price Range
 Assets LiabilitiesTechniqueUnobservable Input (a) Low High
  (in thousands)          
Energy Contracts $ 9,359  $ 960  Discounted Cash Flow  Forward Market Price  $ 13.04  $ 80.50 
FTRs   2,738    575  Discounted Cash Flow  Forward Market Price    (5.10)   10.44 
Total $ 12,097  $ 1,535           
Significant Unobservable Inputs
June 30, 2014
APCo
     Significant Forward Price Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in thousands)          
Energy Contracts$5,320
 $1,773
 Discounted Cash Flow  Forward Market Price  $13.59
 $66.90
 $42.23
FTRs14,987
 140
 Discounted Cash Flow  Forward Market Price  (14.63) 9.26
 1.01
Total$20,307
 $1,913
      
  
  

Significant Unobservable Inputs
March 31, 2014
I&M                
  Fair Value Valuation Significant Forward Price Range
 Assets LiabilitiesTechniqueUnobservable Input (a) Low High
  (in thousands)          
Energy Contracts $ 4,378  $ 1,914  Discounted Cash Flow  Forward Market Price  $ 13.34  $ 59.60 
FTRs   2,567    190  Discounted Cash Flow  Forward Market Price    (5.05)   9.17 
Total $ 6,945  $ 2,104           
                 
Significant Unobservable Inputs
December 31, 2013
I&M                
  Fair Value Valuation Significant Forward Price Range
 Assets LiabilitiesTechniqueUnobservable Input (a) Low High
  (in thousands)          
Energy Contracts $ 6,348  $ 651  Discounted Cash Flow  Forward Market Price  $ 13.04  $ 80.50 
FTRs   1,857    390  Discounted Cash Flow  Forward Market Price    (5.10)   10.44 
Total $ 8,205  $ 1,041           
Significant Unobservable Inputs
December 31, 2013
APCo
       Significant    
 Fair Value Valuation Unobservable Forward Price Range
 Assets Liabilities Technique Input (a) Low High
 (in thousands)        
Energy Contracts$9,359
 $960
 Discounted Cash Flow  Forward Market Price  $13.04
 $80.50
FTRs2,738
 575
 Discounted Cash Flow  Forward Market Price  (5.10) 10.44
Total$12,097
 $1,535
      
  


230


Significant Unobservable Inputs
June 30, 2014
I&M
       Significant Forward Price Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in thousands)          
Energy Contracts$3,608
 $1,202
 Discounted Cash Flow  Forward Market Price  $13.59
 $66.90
 $42.23
FTRs10,612
 95
 Discounted Cash Flow  Forward Market Price  (14.63) 9.26
 1.01
Total$14,220
 $1,297
      
  
  

Significant Unobservable Inputs
December 31, 2013
I&M
176
Significant Unobservable Inputs
March 31, 2014
OPCo              
    Significant    
 Fair Value Valuation Significant Forward Price RangeFair Value Valuation Unobservable Forward Price Range
Assets LiabilitiesTechniqueUnobservable Input (a) Low HighAssets Liabilities Technique Input (a) Low High
 (in thousands)         (in thousands)        
Energy Contracts $ -  $ -  Discounted Cash Flow  Forward Market Price  $ -  $ - $6,348
 $651
 Discounted Cash Flow  Forward Market Price  $13.04
 $80.50
FTRs   3,990    78  Discounted Cash Flow  Forward Market Price    (5.05)  9.17 1,857
 390
 Discounted Cash Flow  Forward Market Price  (5.10) 10.44
Total $ 3,990  $ 78          $8,205
 $1,041
      
  
              
Significant Unobservable Inputs
December 31, 2013
OPCo              
 Fair Value Valuation Significant Forward Price Range
Assets LiabilitiesTechniqueUnobservable Input (a) Low High
 (in thousands)         
Energy Contracts $ -  $ -  Discounted Cash Flow  Forward Market Price  $ -  $ - 
FTRs   3,269    349  Discounted Cash Flow  Forward Market Price    (5.10)  10.44 
Total $ 3,269  $ 349          

Significant Unobservable Inputs
March 31, 2014
PSO                
  Fair Value Valuation Significant Forward Price Range
 Assets LiabilitiesTechniqueUnobservable Input (a) Low High
  (in thousands)          
Energy Contracts $ -  $ -  Discounted Cash Flow  Forward Market Price  $ -  $ - 
FTRs   481    132  Discounted Cash Flow  Forward Market Price    (5.05)   9.17 
Total $ 481  $ 132           
Significant Unobservable Inputs
June 30, 2014
OPCo
       Significant Forward Price Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in thousands)          
FTRs$9,300
 $—
 Discounted Cash Flow  Forward Market Price  $(14.63) $9.26
 $1.01

Significant Unobservable Inputs
March 31, 2014
SWEPCo                
  Fair Value Valuation Significant Forward Price Range
 Assets LiabilitiesTechniqueUnobservable Input (a) Low High
  (in thousands)          
Energy Contracts $ -  $ -  Discounted Cash Flow  Forward Market Price  $ -  $ - 
FTRs   609    167  Discounted Cash Flow  Forward Market Price    (5.05)   9.17 
Total $ 609  $ 167           
Significant Unobservable Inputs
December 31, 2013
OPCo
       Significant    
 Fair Value Valuation Unobservable Forward Price Range
 Assets Liabilities Technique Input (a) Low High
 (in thousands)        
FTRs$3,269
 $349
 Discounted Cash Flow  Forward Market Price  $(5.10) $10.44


231


Significant Unobservable Inputs
June 30, 2014
PSO
       Significant Forward Price Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in thousands)          
FTRs$—
 $3
 Discounted Cash Flow  Forward Market Price  $(14.63) $9.26
 $1.01

Significant Unobservable Inputs
June 30, 2014
SWEPCo
       Significant Forward Price Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in thousands)          
FTRs$—
 $3
 Discounted Cash Flow  Forward Market Price  $(14.63) $9.26
 $1.01

(a)Represents market prices in dollars per MWh.

The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrant Subsidiaries as of June 30, 2014:

Sensitivity of Fair Value Measurements
June 30, 2014
Significant Unobservable InputPositionChange in Input
Impact on Fair Value
Measurement
Forward Market PriceBuyIncrease (Decrease)Higher (Lower)
Forward Market PriceSellIncrease (Decrease)Lower (Higher)


232


10.  11.  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.

177
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 IRS examination of years 2011 and 2012 started in April 2014. 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.  However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities.  Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and 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 2009.



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11.  12.  FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first threesix months of 2014 are shown in the tables below:

   Principal Interest  
Company Type of Debt Amount (a) Rate Due Date Type of Debt Principal Amount (a)Interest Rate Due Date
Issuances:   (in thousands) (%)     (in thousands)(%)  
APCo Senior Unsecured Notes $300,000
4.40 2044
I&M Pollution Control Bonds 100,000
1.75 2018
PSO Other Long-term Debt $ 50,000  Variable 2016  Other Long-term Debt 75,000
Variable 2016

     Principal Interest  
Company Type of Debt Amount Paid Rate Due Date
Retirements and   (in thousands) (%)  
 Principal Payments:         
APCo Land Note $ 8  13.718  2026 
I&M Notes Payable   9,866  Variable 2017 
I&M Notes Payable   5,324  Variable 2016 
I&M Notes Payable   5,214  Variable 2016 
I&M Notes Payable   3,611  2.12  2016 
I&M Other Long-term Debt   2,063  Variable 2015 
I&M Other Long-term Debt   259  6.00  2025 
OPCo Other Long-term Debt   29  1.149  2028 
OPCo Senior Unsecured Notes   225,000  4.85  2014 
PSO Other Long-term Debt   102  3.00  2027 
SWEPCo Notes Payable   1,625  4.58  2032 

(a)Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Company Type of Debt  Principal Amount PaidInterest Rate Due Date
Retirements and Principal Payments:   (in thousands)(%)  
APCo Land Note $16
13.718 2026
APCo Senior Unsecured Notes 200,000
4.95 2015
APCo Other Long-term Debt 300,000
Variable 2015
I&M Notes Payable 19,410
Variable 2017
I&M Notes Payable 13,782
Variable 2016
I&M Notes Payable 10,258
Variable 2016
I&M Notes Payable 7,105
2.12 2016
I&M Notes Payable 4,402
4.00 2014
I&M Other Long-term Debt 4,813
Variable 2015
I&M Other Long-term Debt 522
6.00 2025
I&M Pollution Control Bonds 100,000
6.25 2014
OPCo Other Long-term Debt 48
1.149 2028
OPCo Pollution Control Bonds 79,450
3.25 2014
OPCo Pollution Control Bonds 60,000
3.875 2014
OPCo Senior Unsecured Notes 225,000
4.85 2014
PSO Other Long-term Debt 206
3.00 2027
PSO Pollution Control Bonds 33,700
5.25 2014
SWEPCo Notes Payable 1,625
4.58 2032

In AprilJuly 2014, I&M retired $13$9 million of Notes Payable related to DCC Fuel.

In July 2014, OPCo retired $35 million of Securitization Bonds.

In July 2014, SWEPCo issued a $100 million three-year term credit facility and drew the full amount.

As of March 31,June 30, 2014, trustees held on behalf of I&M and OPCo, $40 million and $460$395 million, respectively, of their reacquired Pollution Control Bonds.

178
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.

234



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 generation plants.  Because of their respective ownership of such plants, this reserve applies to APCo and I&M.

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 PSO 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 a majority of AEP’s nonutility subsidiaries.  The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC.  The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31,June 30, 2014 and December 31, 2013 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 threesix months ended March 31,June 30, 2014 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 March 31, 2014 Limit 
Maximum
Borrowings
from the
Utility
Money Pool
 
Maximum
Loans to the
Utility
Money Pool
 
Average
Borrowings
from the
Utility
Money Pool
 
Average
Loans to the
Utility
Money Pool
 
Net Loans to
(Borrowings from)
the Utility Money
Pool as of
June 30, 2014
 
Authorized
Short-term
Borrowing
Limit
 (in thousands) (in thousands)
APCo $ -  $ 249,630  $ -  $ 164,681  $ 245,516  $ 600,000  $44,215
 $542,186
 $15,653
 $153,179
 $28,794
 $600,000
I&M  -   158,857   -   92,303   59,162   500,000  68,332
 158,857
 38,811
 65,075
 (33,847) 500,000
OPCo  55,640   405,350   25,930   135,747   (27,108)  600,000  120,264
 405,350
 35,792
 114,371
 (34,723) 400,000
PSO  121,100   -   58,500   -   (70,119)  300,000  176,950
 —
 87,805
 —
 (124,800) 300,000
SWEPCo  130,258   -   61,132   -   (117,342)  350,000  153,503
 —
 92,467
 —
 (79,098) 350,000

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

 Three Months Ended March 31, Six Months Ended June 30,
 2014  2013  2014 2013
Maximum Interest Rate  0.33 %  0.43 % 0.33% 0.43%
Minimum Interest Rate  0.28 %  0.35 % 0.24% 0.32%


235
179


The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the threesix months ended March 31,June 30, 2014 and 2013 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
 Three Months Ended March 31, Three Months Ended March 31, 
Average Interest Rate
for Funds Borrowed
from the Utility Money Pool for
Six Months Ended June 30,
 
Average Interest Rate
for Funds Loaned
to the Utility Money Pool for
Six Months Ended June 30,
Company 2014  2013 2014  2013  2014 2013 2014 2013
APCo  - %  0.38 %  0.31 %  0.37 % 0.26% 0.36% 0.29% 0.36%
I&M  - %  0.36 %  0.31 %  0.37 % 0.26% 0.36% 0.30% 0.35%
OPCo  0.31 %  0.36 %  0.29 %  0.37 % 0.27% 0.35% 0.29% 0.37%
PSO  0.31 %  0.36 %  - %  0.38 % 0.28% 0.34% —% 0.38%
SWEPCo  0.31 %  - %  - %  0.38 % 0.28% 0.34% —% 0.37%

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 5.

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.

AEP Credit's receivables securitization agreement provides a commitment of $700$750 million from bank conduits to purchase receivables.  A commitment of $385The agreement was increased in June 2014 from $700 million and expires in June 2014.  The remaining commitment of $315 million expires in June 2015.  AEP Credit intends to extend or replace the agreement expiring in June 2014 on or before its maturity.2016.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of March 31,June 30, 2014 and December 31, 2013 was as follows:

  March 31, December 31, June 30, December 31,
CompanyCompany 2014  2013  2014 2013
  (in thousands) (in thousands)
APCoAPCo $ 175,738  $ 156,599  $156,930
 $156,599
I&MI&M   154,510   139,257  145,273
 139,257
OPCoOPCo   350,735   324,287  359,370
 324,287
PSOPSO  111,522   115,260  149,600
 115,260
SWEPCoSWEPCo  145,648   149,337  179,617
 149,337

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

  Three Months Ended March 31, Three Months Ended June 30, Six Months Ended June 30,
CompanyCompany 2014  2013  2014 2013 2014 2013
  (in thousands) (in thousands)
APCoAPCo $ 2,423  $ 1,556  $2,037
 $1,459
 $4,460
 $3,015
I&MI&M   2,040   1,452  1,785
 1,530
 3,825
 2,982
OPCoOPCo   7,498   4,669  6,647
 4,695
 14,145
 9,364
PSOPSO  1,323   1,414  1,349
 1,351
 2,672
 2,765
SWEPCoSWEPCo  1,566   1,380  1,579
 1,384
 3,145
 2,764


236
180


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

  Three Months Ended March 31, Three Months Ended June 30, Six Months Ended June 30,
CompanyCompany 2014  2013  2014 2013 2014 2013
  (in thousands) (in thousands)
APCoAPCo $ 437,196  $ 398,193  $345,963
 $342,984
 $783,159
 $741,177
I&MI&M   407,150   351,830  353,030
 361,417
 760,180
 713,247
OPCoOPCo   686,627   696,958  626,025
 661,959
 1,312,652
 1,358,917
PSOPSO  290,217   240,275  325,536
 321,620
 615,753
 561,895
SWEPCoSWEPCo  390,588   331,936  420,909
 389,076
 811,497
 721,012


237


12.  13.  VARIABLE INTEREST ENTITIES

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

SWEPCo is the primary beneficiary of Sabine.  I&M is the primary beneficiary of DCC Fuel.  OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding.  APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding.  SWEPCo holds a significant variable interest in DHLC.  Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC.  I&M and OPCo each hold a significant variable interest in AEGCo.

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the three months ended March 31,June 30, 2014 and 2013 were $39$41 million and $44$40 million, respectively, and for the six months ended June 30, 2014 and 2013 were $80 million and $84 million, respectively.  See the tablestable 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
March 31, 2014 and December 31, 2013
(in thousands)
  Sabine
ASSETS 2014  2013 
Current Assets $ 61,675  $ 66,478 
Net Property, Plant and Equipment   153,928    157,274 
Other Noncurrent Assets   50,140    51,211 
Total Assets $ 265,743  $ 274,963 
       
LIABILITIES AND EQUITY      
Current Liabilities $ 29,257  $ 32,812 
Noncurrent Liabilities   236,142    241,673 
Equity   344    478 
Total Liabilities and Equity $ 265,743  $ 274,963 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
June 30, 2014 and December 31, 2013
(in thousands)
  Sabine
ASSETS 2014 2013
Current Assets $59,604
 $66,478
Net Property, Plant and Equipment 152,818
 157,274
Other Noncurrent Assets 50,619
 51,211
Total Assets $263,041
 $274,963
     
LIABILITIES AND EQUITY  
  
Current Liabilities $28,892
 $32,812
Noncurrent Liabilities 233,752
 241,673
Equity 397
 478
Total Liabilities and Equity $263,041
 $274,963


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181


I&M has nuclear fuel lease agreements with DCC Fuel II 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 March 31,June 30, 2014 and 2013 were $25$32 million and $26$38 million, respectively, and for the six months ended June 30, 2014 and 2013 were $56 million and $64 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months.  Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  In October 2013, the lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC.  See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s condensed balance sheets.

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

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
March 31, 2014 and December 31, 2013
(in thousands)
  DCC Fuel
ASSETS 2014  2013 
Current Assets $ 109,374  $ 117,762 
Net Property, Plant and Equipment   129,013    156,820 
Other Noncurrent Assets   44,853    60,450 
Total Assets $ 283,240  $ 335,032 
       
LIABILITIES AND EQUITY      
Current Liabilities $ 100,141  $ 107,815 
Noncurrent Liabilities   183,099    227,217 
Total Liabilities and Equity $ 283,240  $ 335,032 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
June 30, 2014 and December 31, 2013
(in thousands)
  DCC Fuel
ASSETS 2014 2013
Current Assets $88,084
 $117,762
Net Property, Plant and Equipment 96,821
 156,820
Other Noncurrent Assets 34,856
 60,450
Total Assets $219,761
 $335,032
     
LIABILITIES AND EQUITY  
  
Current Liabilities $84,086
 $107,815
Noncurrent Liabilities 135,675
 227,217
Total Liabilities and Equity $219,761
 $335,032

Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Phase-inphase-in recovery property.  Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant.  Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding.  The securitized bonds totaled $267 million and $267 million as of March 31,June 30, 2014 and December 31, 2013, respectively, and are included in current and long-term debt on the condensed balance sheets.  Ohio Phase-in-Recovery Funding has securitized assets of $127$122 million and $132 million as of March 31,June 30, 2014 and December 31, 2013, respectively, which are presented separately on the face of the condensed balance sheets.  The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO.  In August 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to OPCo or any other AEP entity.  OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs.


239
182


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

OHIO POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
March 31, 2014 and December 31, 2013
(in thousands)
  Ohio Phase-in-
  Recovery Funding
ASSETS 2014  2013 
Current Assets $ 35,958  $ 23,198 
Other Noncurrent Assets (a)   241,814    251,409 
Total Assets $ 277,772  $ 274,607 
       
LIABILITIES AND EQUITY      
Current Liabilities $ 59,590  $ 36,470 
Noncurrent Liabilities   216,845    236,800 
Equity   1,337    1,337 
Total Liabilities and Equity $ 277,772  $ 274,607 
OHIO POWER COMPANY AND SUBSIDIARIES

VARIABLE INTEREST ENTITIES
June 30, 2014 and December 31, 2013
(in thousands)
 
Ohio
Phase-In Recovery
Funding
ASSETS
2014
2013
Current Assets
$47,511

$23,198
Other Noncurrent Assets (a)
232,219

251,409
Total Assets
$279,730

$274,607
 
 



LIABILITIES AND EQUITY
 



Current Liabilities
$60,510

$36,470
Noncurrent Liabilities
217,883

236,800
Equity
1,337

1,337
Total Liabilities and Equity
$279,730

$274,607
(a)Includes an intercompany item eliminated in consolidation as of March 31,June 30, 2014 and December 31, 2013 of $112$108 million and $116 million, respectively.

Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance.  Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant.  Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding.  The securitized bonds totaled $380 million and $380 million as of March 31,June 30, 2014 and December 31, 2013, respectively, and are included in current and long-termlong term debt on the condensed balance sheets.  Appalachian Consumer Rate Relief Funding has securitized assets of $365$361 million and $369 million as of March 31,June 30, 2014 and December 31, 2013, respectively, which are presented separately on the face of the condensed balance sheets.  The phase-in recovery property represents the right to impose and collect WVWest Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC.  In November 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to APCo or any other AEP entity.  APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs.


240


The balances below represent the assets and liabilities of Appalachian Consumer Rate Relief Funding that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
March 31, 2014 and December 31, 2013
(in thousands)
  Appalachian Consumer
  Rate Relief Funding
ASSETS 2014  2013 
Current Assets $ 15,981  $ 5,891 
Other Noncurrent Assets (a)   373,521    378,029 
Total Assets $ 389,502  $ 383,920 
       
LIABILITIES AND EQUITY      
Current Liabilities $ 27,682  $ 14,000 
Noncurrent Liabilities   359,919    368,018 
Equity   1,901    1,902 
Total Liabilities and Equity $ 389,502  $ 383,920 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
June 30, 2014 and December 31, 2013
(in thousands)
  
Appalachian Consumer Rate
Relief Funding
ASSETS 2014 2013
Current Assets $23,121
 $5,891
Other Noncurrent Assets (a) 369,014
 378,029
Total Assets $392,135
 $383,920
     
LIABILITIES AND EQUITY  
  
Current Liabilities $30,327
 $14,000
Noncurrent Liabilities 359,907
 368,018
Equity 1,901
 1,902
Total Liabilities and Equity $392,135
 $383,920

(a)Includes an intercompany item eliminated in consolidation as of March 31,June 30, 2014 of and December 31, 2013 of $4 million and $4 million, respectively.

183
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 March 31,June 30, 2014 and 2013 were $2$6 million and $18$13 million, respectively, and for the six months ended June 30, 2014 and 2013 were $8 million and $31 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:

 March 31, 2014 December 31, 2013
 As Reported on Maximum As Reported on Maximum
 the Balance SheetExposurethe Balance Sheet Exposure June 30, 2014 December 31, 2013
Company 
As Reported on
the Balance Sheet
 
Maximum
Exposure
 
As Reported on
the Balance Sheet
 
Maximum
Exposure
 (in thousands) (in thousands)
Capital Contribution from SWEPCo $ 7,643  $ 7,643  $ 7,643  $ 7,643  $7,643
 $7,643
 $7,643
 $7,643
Retained Earnings   1,910   1,910   1,600   1,600  2,326
 2,326
 1,600
 1,600
SWEPCo's Guarantee of Debt   -    85,190    -    61,348  —
 115,829
 —
 61,348
                 
Total Investment in DHLC $ 9,553  $ 94,743  $ 9,243  $ 70,591  $9,969
 $125,798
 $9,243
 $70,591

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

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operations.  AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure.  However, AEP subsidiaries do not have control over AEPSC.  AEPSC is consolidated by AEP.  In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

Total AEPSC billings to the Registrant Subsidiaries were as follows:

 Three Months Ended March 31, Three Months Ended June 30, Six Months Ended June 30,
Company 2014  2013  2014 2013 2014 2013
 (in thousands) (in thousands)
APCo $ 50,136  $ 39,040  $53,959
 $41,496
 $104,096
 $80,537
I&M  31,969    27,498  30,103
 28,706
 62,073
 56,204
OPCo  39,049    54,069  40,441
 57,351
 79,490
 111,420
PSO  24,439    18,161  22,889
 19,807
 47,329
 37,969
SWEPCo  33,023    27,480  32,718
 29,595
 65,741
 57,075

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

 March 31, 2014 December 31, 2013
 As Reported on the Maximum As Reported on the Maximum June 30, 2014 December 31, 2013
Company Balance Sheet Exposure Balance Sheet Exposure 
As Reported on the
Balance Sheet
 
Maximum
Exposure
 
As Reported on the
Balance Sheet
 
Maximum
Exposure
 (in thousands) (in thousands)
APCo $ 19,304  $ 19,304  $ 20,191  $ 20,191  $18,626
 $18,626
 $20,191
 $20,191
I&M  12,040    12,040    12,864    12,864  10,361
 10,361
 12,864
 12,864
OPCo  14,046    14,046    31,425    31,425  14,116
 14,116
 31,425
 31,425
PSO  9,330    9,330    10,596    10,596  7,845
 7,845
 10,596
 10,596
SWEPCo  12,833    12,833    13,520    13,520  9,758
 9,758
 13,520
 13,520

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 has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014.  AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo.  I&M is considered to have a significant interest in AEGCo due to these transactions.  I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations.  In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP.  For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 12 in the 2013 Annual Report.

Total billings from AEGCo were as follows:

 Three Months Ended March 31, Three Months Ended June 30, Six Months Ended June 30,
Company 2014  2013  2014 2013 2014 2013
 (in thousands) (in thousands)
I&M $ 70,422  $ 58,535  $65,190
 $53,191
 $135,612
 $111,726
OPCo -    38,711  —
 31,910
 —
 70,621

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

 March 31, 2014 December 31, 2013
 As Reported on Maximum As Reported on Maximum June 30, 2014 December 31, 2013
Company the Balance Sheet Exposure the Balance Sheet Exposure 
As Reported on the
Balance Sheet
 
Maximum
Exposure
 
As Reported on the
Balance Sheet
 
Maximum
Exposure
 (in thousands) (in thousands)
I&M $ 24,364  $ 24,364  $ 23,916  $ 23,916  $23,801
 $23,801
 $23,916
 $23,916
OPCo -   -    12,810    12,810  —
 —
 12,810
 12,810


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185


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 2013 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

Customer Demand

In comparison to 2013, heating degree days infor the six months ended June 30, 2014 were up 40%32% in AEP’sAEP's western region and 24%20% in AEP’sAEP's eastern region. Weather-normalized retail sales volumes for the firstsecond quarter of 2014 decreased by 0.5% from their levels for the second quarter of 2013 and increased by 1.5%0.6% for the first six months of 2014 from their levels for the first quartersix months of 2013. First quarter 2014 weather-adjusted residentialIn comparison to 2013, AEP's industrial sales volume decreased 0.5% and commercial customer sales were up 4.4% and 2.9%, respectively, from their levels1.6% for the first quarter of 2013.  Residentialthree and commercial customer counts grew 0.4% and 0.8% in the first quarter ofsix months ended June 30, 2014, respectively, from the first quarter of 2013.

AEP’s industrial sales volumes in the first quarter of 2014 decreased 2.9% from the first quarter of 2013 due mainly to the closure of Ormet, a large aluminum company. Ormet had a contract to purchase power from OPCo through 2018.  In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down its operations effective immediately.  Excluding Ormet, total AEP first quarterAEP's six months ended June 30, 2014 industrial sales volumes increased 2.2%3.4% over the first quarter ofsix months ended June 30, 2013. TheFollowing Ormet's closure in October 2013, the loss of Ormet's load will not have a material impact on future gross margin because power previously sold to Ormet will be available for sale into generally higher priced wholesale markets.

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 2013 Annual Report.  Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  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.


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Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of March 31,June 30, 2014, 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 
Through 2020
Estimated Environmental Investment
CompanyCompany Low High Low High
 (in millions)  (in millions) 
APCoAPCo $ 310  $ 360  $310
 $360
I&MI&M   410    470  370
 430
PSOPSO   280    320  270
 310
SWEPCoSWEPCo   910    1,060  910
 1,010

Several proposed regulations issued during 2014, including CO2 and Clean Water Act, are currently under review and management cannot currently predict the impact these programs may have on future resource plans or the existing generating fleet; however, the costs may be substantial. For APCo, the projected environmental investment above includes the conversion of 470 MWs of coal generation to natural gas capacity.  If natural gas conversion is not completed, the units could be closed sooner than planned.

The 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 (SIPs) or federal implementation plans (FIPs) that impose more stringent standards, than the proposed rules, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.

Subject to the factors listed above and based upon continuing evaluation, management has given notice to the applicable RTO’s of intentintends 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 3 235 235 
APCo Glen Lyn Plant 335 335 
APCo Kanawha River Plant 400 400 
APCo/AGR Sporn Plant Units 1-4 600 600 
I&M Tanners Creek Plant Units 1-4 995 995 
PSO Northeastern Station, Unit 4 470 470 
SWEPCo Welsh Plant, Unit 2 528 528 

As of March 31,June 30, 2014, the net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the plants in the table above was $727$709 million.

PSO received Federal EPA approval of the Oklahoma SIP, in February 2014, related to the environmental compliance plan for Northeastern Station, Unit 3.


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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.

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Clean Air Act Requirements

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

The Federal EPA issued the Clean Air Interstate Rule (CAIR) in 2005 requiring specific reductions in SO2 and NOx emissions from power plants.  In 2008, the District of Columbia Circuit Court of Appeals issued a decision remanding CAIR to the Federal EPA. The Federal EPA issued the Cross-State Air Pollution Rule (CSAPR) (discussed in detail below) in August 2011 to replace CAIR. The CSAPR was challenged in the courts. The U.S. Court of Appeals for the District of Columbia Circuit issued an order in 2011 staying the effective date of the rule pending judicial review. In 2012, a panel of the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing CAIR until a replacement rule is finalized. That decision has been appealed to the U.S. Supreme Court. That decision was appealed to the U.S. Supreme Court, which reversed the decision in part and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit. Nearly all of the states in which the Registrant Subsidiaries’ power plants are located are covered by CAIR. See "Cross-State Air Pollution Rule (CSAPR)" section below.

The Federal EPA issued the final maximum achievable control technology (MACT) standards for coal and oil-fired power plants in 2012. See “Mercury and Other Hazardous Air Pollutants (HAPs) Regulation” section below.

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas. BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. CAVR will be implemented through individual state implementation plans (SIPs)SIPs or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs).FIPs. The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas. 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 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.Circuit.

In 2009, the Federal EPA issued a final mandatory reporting rule for CO2 and other greenhouse gases covering a broad range of facilities emitting in excess of 25,000 tons of CO2 emissions per year. The Federal EPA issued a final endangerment finding for greenhouse gas emissions from new motor vehicles in 2009. The Federal EPA determined that greenhouse gasemissions from stationary sources will be subject to regulation under the CAA beginning January 2011 and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, SIP calls and FIPs. The Federal EPA has proposed to include CO2 emissions in standards that apply to new electric utility units and will consider whether such standards are appropriate for other source categories in the future. See "CO2 Regulation" section below.

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.


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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 2011, the Federal EPA issued CSAPR. Certain revisions to the rule were finalized in 2012. CSAPR relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states. Interstate trading of allowances is allowed on a restricted sub-regional basis. Arkansas and Louisiana are subject only to the seasonal NOx program in the rule. Texas is subject to the
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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 2011, the court granted the motions for stay. In 2012, the court issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the CAIR 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. In April 2014, the U.S. Supreme Court issued a decision reversing in part the decision of the U.S. Court of Appeals for the District of Columbia Circuit and remanding the case for further proceedings consistent with the opinion. The parties have filed motions to govern further proceedings. The Federal EPA has filed a motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. Until the court acts on this motion, CAIR will remain in effect. 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.no briefing schedules have been established. Management cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis. In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. The effective date of the final rule was April 16, 2012 and compliance is required within three years. The AEP System is participating through various organizations in the petitionsPetitions for administrative reconsideration and judicial review that have beenwere 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. The Federal EPA issued revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions in March 2013. The Federal EPA is still considering additional changes to the start-up and shut down provisions. In April 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the April 2012 final rule.

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. AThe AEP System obtained a one-year administrative extension may be available if the extension is necessary for several units to facilitate the installation of controls or to avoid a serious reliability problem. In addition, the Federal EPA issued an

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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 isremains 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 participated in petitions for review filed indeadlines and the U.S. Courtlack of Appeals forcoordination among the District of Columbia Circuit by several organizations of which the Registrant Subsidiaries are members.  Certain issues related to the standards for new coal-fired units have been severed from the main caseMercury and are being held in abeyance pending completion of the Federal EPA’s reconsideration proceeding.  In April 2014, the appellate court issued a decision denying all of the petitions for review of the April 2012 final rule.Air Toxics Standards schedule and other environmental requirements.

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CO2 Regulation

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.units. The new proposal was issued in September 2013 and requires new large natural gas units to meet 1,000 pounds of CO2 per MWh of electricity generated and small natural gas units to meet 1,100 pounds of CO2 per MWh. New coal-fired units are required to meet the 1,100 pounds of CO2 per MWh limit, with the option to meet the tighter limits if they choose to average emissions over multiple years. ThisThe proposal was published in the Federal Register in January 2014.

The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from existing, modified and reconstructed electric generating units (EGUs) and to issue guidelines for existing EGUs before June 2014, to finalize those standards by June 2015 and to require states to submit revisions to their implementation plans including such standards no later than June 2016. The President directed the Federal EPA, in developing this proposal, to directly engage states, leaders in the power sector, labor leaders and other stakeholders, to tailor the regulations to reduce costs, to develop market-based instruments and allow regulatory flexibilities and “assure that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power.” The Federal EPA issued proposed guidelines establishing state goals for CO2 emissions from existing EGUs and proposed regulations governing emissions of CO2 from modified and reconstructed EGUs in June 2014 and comments are due in October 2014. The guidelines use a “portfolio” approach to reducing emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units, expanding renewable resources and increasing customer energy efficiency. The standards for modified and reconstructed units include several options, including use of historic baselines or energy efficiency audits to establish source-specific CO2 emission rates or to limit CO2 emissions to no more than 1,900 pounds per MWh at larger coal units and 2,100 pounds per MWh at smaller coal units. These proposed regulations are currently under review. 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. AIn 2012, the U.S. Court of Appeals for the District of Columbia Circuit denied a petition for rehearing was filed whichrehearing. In June 2014, the court denied in December 2012.  The U.S. Supreme Court granted several petitions for review and will determine whetherdetermined that the Federal EPA madewas not compelled to regulate CO2 emissions from stationary sources under the Title V or PSD programs as a reasonable determination thatresult of its adoption of the motor vehicle standards, triggerbut that sources otherwise required to obtain a PSD and Title V permitting obligationspermit may be required to perform a Best Available Control Technology analysis for stationary sources.  A decision is expected by June 2014.CO

2 emissions if they exceed a reasonable level. The Federal EPA also finalized a rule in June 2012 that retainsmust undertake additional rulemaking to implement the current emission thresholds for permitting stationary sources under the PSDcourt’s decision 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.establish an appropriate level.

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 and also FGD gypsum generated at some coal fired plants. 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 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

247


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. In 2013, the Federal EPA also issued a notice of data availability requesting comments on a narrow set of issues.

Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule. The Federal EPA opposed the petition and sought additional time to coordinate the issuance of a final rule with the issuance of new effluent limitations under the Clean Water Act (CWA) for utility facilities. In October 2013, the U.S. District Court for the District of Columbia issued a final order partially ruling in favor of the Federal EPA for dismissal of two counts, ruling in favor of the environmental organizations on one count and directing the Federal EPA to provide the court with a proposed schedule for completion of the rulemaking. In January 2014, the parties filed a motion with theThe court to establishestablished December 19, 2014 as the Federal EPA’s deadline for publication of the rule.  The court will establish a deadline for the final rule following a comment period for interested parties.

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In February 2014, the Federal EPA completed a risk evaluation of the beneficial uses of coal fly ash in concrete and flue gas desulfurizationFGD gypsum in wallboard and concluded that the Federal EPA supports these beneficial uses. Currently, approximately 40% of the coal ash and other residual products from the AEP System’s generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses. Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes. In addition, surface impoundments and landfills to manage these materials are currently used at the generating facilities. The Registrant Subsidiaries will incur significant costs to upgrade or close and replace their existing facilities under the proposed solid waste management alternative. Regulation of these materials as hazardous wastes would significantly increase these costs. As the rule is not final, management is unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

Clean Water Act Regulations

In 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 aThe final rule is expectedwas released by the Federal EPA in 2014.  Management is preparingMay 2014 and affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to begin activitiescomply with the impingement standard and requires site-specific studies to implementdetermine appropriate entrainment compliance measures at facilities withdrawing more than 125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, following its issuanceare not expected to require any technology changes. Facilities subject to both the impingement standard and an analysissite-specific entrainment studies will typically be given at least three years to conduct and submit the results of those studies to the final requirements.permit agency. Compliance timeframes will then be established by the permit agency through each facility’s National Pollutant Discharge Elimination System (NPDES) permit for installation of any required technology changes, as those permits are renewed over the next five to eight years.

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 September 2015. 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 continues to review the proposal in detail to evaluate whether the plants are currently meeting the proposed limitations, what technologies have been incorporated into the long-range plans and what additional costs might be incurred if the Federal EPA's most stringent options were adopted. Management submitted detailed comments to the Federal EPA in September 2013 and participated in comments filed by various organizations of which the AEP System companies are members.

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In MarchApril 2014, the Federal EPA and the U.S. Army Corps of Engineers jointly announced that they will be issuingissued a proposed rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases and released a pre-publication version ofpublished the proposed rule.rule in the Federal Register. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This proposed jurisdictional definition will apply to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are: permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. Management agrees that clarity and efficiency in the permitting process is needed. Management is concerned that the proposed rule introduces new concepts and could subject more of the Registrant Subsidiaries’ operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. Management will continue to evaluate the rule and its financial impact on the AEP System. Management plans to submit comments and also participate in the preparation of comments to be filed by various organizations of which the AEP System companies are members.

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Climate Change

National public policy makers and regulators in the 10nine 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 actively participating 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.

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 2013 Form 10-K under the headings entitled “Environmental and Other Matters” and “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries.”

ACCOUNTING PRONOUNCEMENTS

Pronouncements Effective in the Future

The FASB issued ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held for saleheld-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. Management plans to adopt ASU 2014-08 effective January 1, 2015.


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The FASB issued ASU 2014-09 "Revenue from Contracts with Customers" clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2017.

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.

CONTROLS AND PROCEDURES

During the firstsecond quarter of 2014, 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
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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 March 31,June 30, 2014, 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.

Effective March 1, 2014, the SPP transitioned from an Energy Imbalance Service Market to a fully integrated market that consists of both a Day-Ahead and Real Time Balancing Market.  In connection with SPP’s transition to a fully integrated market, PSO and SWEPCo implemented or modified a number of business processes and controls to facilitate participation and settlementThere was no change in the SPP integrated market.  Apart from this, there have been no material changesRegistrants’ 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 firstsecond quarter of 2014 that have materially affected, or areis reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.     Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 5incorporated herein by reference.


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Item 1A.  Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2013 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 2013 Annual Report on Form 10-K.

GENERAL RISKS OF OUR REGULATED OPERATIONS

Ohio may require us to refund revenue that we have collected. –- Affecting AEP and OPCo

Ohio law requires that the PUCO determine on an annual basis if rate adjustments included in prior orders resulted in significantly excessive earnings. If the PUCO determines there were significantly excessive earnings, the excess amount could be returned to customers. In November 2013,May 2014, OPCo filed its 20122013 significantly excessive earnings filing with the PUCO.  OPCo plans to file its 2013 SEET filing in May 2014. If the PUCO determines that OPCo’s earnings were significantly excessive, and requires OPCo to return a portion of its revenues to customers, it could reduce future net income and cash flows and impact financial condition.

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

In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC.  The filing included a $5 million annual increase to be effective August 2014.  SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. These increases are subject to LPSC review. If SWEPCo cannot ultimately recover its costs that are the subject of this request, it could reduce future net income and cash flows.flows and impact financial condition.

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Request for rate and other recovery in Virginia for generation and distribution service may not be approved in its entirety. –- Affecting AEP and APCo

In March 2014, APCo filed a biennial generation and distribution base rate biennial reviewcase with the Virginia SCC. APCo did not request an increase in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to the changes in the expected service life of certain plants. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to certain deferred costs. If the Virginia SCC denies all or part of the requested rate and other recovery, it could reduce future net income and cash flows.flows and impact financial condition.

Ohio may require a reduction in our 2012 and 2013 fuel deferrals. –- Affecting AEP and OPCo

In AprilMay 2014, the PUCO-selected outside consultant provided its preliminary draftfinal report related to their 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. In addition to this report, the PUCO will also consider the results of the pending audit of the recovery of fixed fuel costs. If the PUCO does not permit full recovery of OPCo’s FAC deferral, it could reduce future net income and cash flows and impact financial condition.

Request for rate and other recovery in West Virginia may not be approved in its entirety. - Affecting AEP and APCo

In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $181 million, based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units. The filing also requested amortization of $89 million over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $45 million annually to recover total vegetation management costs. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Regulation of CO2 emissions, either through legislation or by the Federal EPA, could materially increase costs to us and our customers or cause some of our electric generating units to be uneconomical to operate or maintain. - Affecting each Registrant

The U.S. Congress has not taken any significant steps toward enacting legislation to control CO2emissions since 2009.  In December 2009, the Federal EPA issued a final endangerment finding under the CAA regarding emissions from motor vehicles.  The Federal EPA also finalized CO2 emission standards for new motor vehicles, and issued a rule that implements a permitting program for new and modified stationary sources of CO2 emissions in a phased manner.  Several groups have filed challenges to the endangerment finding and the Federal EPA’s subsequent rulemakings.  The Supreme Court agreed to review whether the Federal EPA reasonably determined that establishing standards for new motor vehicles automatically triggered regulation of stationary sources through the prevention of significant deterioration and Title V permitting programs, and determined that the Federal EPA was neither compelled nor authorized to automatically regulate stationary sources of CO2 emissions under these programs, but that the Federal EPA could establish requirements for best available control technology reviews of CO2 emissions for sources otherwise required to obtain a Prevention of Significant Deterioration permit if their emissions exceed a reasonable level.  The Federal EPA must undertake additional rulemaking to establish such requirements and a reasonable level.

In 2012, the Federal EPA issued a proposed CO2 emissions standard for new power generation sources.  In response to the comments submitted on this proposed rule, and in accordance with a directive from the President, EPA withdrew the April 2012 proposed rule and has issued a new proposal.  This proposed rule includes separate, but equivalent, standards for natural gas and coal-fired units, based on the use of partial carbon capture and storage at coal units.  In June 2014, the Federal EPA issued standards for modified and reconstructed units, and a guideline for the development of state implementation plans that would reduce carbon emissions from existing utility units. The guidelines for existing sources include aggressive emission rate goals that are composed of a number of measures.  Management believes some policy approaches being discussed would have significant and widespread negative consequences for the national economy and major U.S. industrial enterprises, including AEP and our customers.

If CO2 and other emission standards are imposed, the standards could require significant increases in capital expenditures and operating costs and could impact the dates for retirement of our coal-fired units.  We typically recover costs of complying with new requirements such as the potential CO2 and other greenhouse gases emission standards from customers through regulated rates in regulated jurisdictions.  For our sales of energy based on market rate authority, however, there is no such recovery mechanism.  Failure to recover these costs, should they arise, could reduce our future net income and cash flows and possibly harm our financial condition.


Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

None

Item 4.  Mine Safety Disclosures

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of DHLC, and AGR and KPCo, through their use of the Conner Run fly ash impoundment, are subject to the provisions of the Mine Act.


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The Dodd-Frank Wall Street Reform and Consumer Protection Act and its related regulations require companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 contains the notices of violation and proposed assessments received by DHLC and Conner Run under the Mine Act for the quarter ended March 31, 2014.June 30, 2014.

Item 5.  Other Information

None

Item 6.  Exhibits

10 – AEP System Stock Ownership Requirement Plan Amended and Restated as of January 1, 2014

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
 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:  April 25, 2014


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 25, 2014


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