Unassociated Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended March 31, 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.
           
Yes
X
  
No
    

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate websites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).
           
Yes
X
  
No
    

Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
X
  
Accelerated filer
    
           
Non-accelerated filer
    
Smaller reporting company
    

Indicate by check mark whether Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers or smaller reporting companies.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
    
Accelerated filer
    
           
Non-accelerated filer
X
  
Smaller reporting company
    

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
Yes
    
No
X
  

Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

 
 
 

     
Number of shares of common stock outstanding of the registrants as of
April 23, 2014
       
American Electric Power Company, Inc.
    
488,083,018
     
($6.50 par value)
Appalachian Power Company
    
13,499,500
     
(no par value)
Indiana Michigan Power Company
    
1,400,000
     
(no par value)
Ohio Power Company
    
27,952,473
     
(no par value)
Public Service Company of Oklahoma
    
9,013,000
     
($15 par value)
Southwestern Electric Power Company
    
7,536,640
     
($18 par value)

 
 
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
March 31, 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 Statements
        
29
 
Index of Condensed Notes to Condensed Consolidated Financial Statements
    
35
                     
Appalachian Power Company and Subsidiaries:
              
 
Management’s Narrative Discussion and Analysis of Results of Operations
    
74
 
Condensed Consolidated Financial Statements
        
78
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
84
                     
Indiana Michigan Power Company and Subsidiaries:
              
 
Management’s Narrative Discussion and Analysis of Results of Operations
    
86
 
Condensed Consolidated Financial Statements
        
90
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
96
                     
Ohio Power Company and Subsidiaries:
              
 
Management’s Narrative Discussion and Analysis of Results of Operations
    
98
 
Condensed Consolidated Financial Statements
        
103
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
109
                     
Public Service Company of Oklahoma:
              
 
Management’s Narrative Discussion and Analysis of Results of Operations
    
111
 
Condensed Financial Statements
            
114
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
120
                     
Southwestern Electric Power Company Consolidated:
            
 
Management’s Narrative Discussion and Analysis of Results of Operations
    
122
 
Condensed Consolidated Financial Statements
        
125
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
131
                     
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
      
132
                     
Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries
      
186
                     
Controls and Procedures               192
 
 
 
 
 
Part II.  OTHER INFORMATION
              
                     
 
Item 1.
   Legal Proceedings        
193
 
Item 1A.
   Risk Factors        
193
 
Item 2.
   Unregistered Sales of Equity Securities and Use of Proceeds
194
 
Item 4.
   Mine Safety Disclosures      
194
 
Item 5.
   Other Information        
194
 
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      
                   
SIGNATURE                 195
  
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.
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.
BlueStar
  
BlueStar Energy Holdings, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.  BlueStar began doing business as AEP Energy, Inc. in June 2012.
CAA
  
Clean Air Act.
CLECO
  
Central Louisiana Electric Company, a nonaffiliated utility company.
CO2
  
Carbon dioxide and other greenhouse gases.
Cook Plant
  
Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CRES 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.
ERCOT
  
Electric Reliability Council of Texas regional transmission organization.
 
 
i
 
Term   Meaning
     
ESP  
Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETT
  
Electric Transmission Texas, LLC, an equity interest joint venture between AEP and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FAC
  
Fuel Adjustment Clause.
FASB
  
Financial Accounting Standards Board.
Federal EPA
  
United States Environmental Protection Agency.
FERC
  
Federal Energy Regulatory Commission.
FGD
  
Flue Gas Desulfurization or scrubbers.
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.
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
 
Term   Meaning
     
PUCO   Public Utilities Commission of Ohio.
PUCT
  
Public Utility Commission of Texas.
Registrant Subsidiaries
  
AEP subsidiaries which are SEC registrants; APCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts
  
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
  
A 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, 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:

·
The economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory.
·
Inflationary or deflationary interest rate trends.
·
Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·
The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
·
Electric load, customer growth and the impact of retail competition, particularly in Ohio.
·
Weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs.
·
Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·
Availability of necessary generation capacity and the performance of our generation plants.
·
Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·
Our 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.
·
New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation, cost recovery and/or profitability of our generation plants and related assets.
·
Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
·
A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
·
Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
·
Resolution of litigation.
·
Our ability to constrain operation and maintenance costs.
·
Our ability to develop and execute a strategy based on a view regarding prices of electricity and other energy-related commodities.
·
Prices and demand for power that we generate and sell at wholesale.
·
Changes in technology, particularly with respect to new, developing, alternative or distributed sources of generation.
·
Our 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.
·
Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.
·
Changes in utility regulation and the allocation of costs within regional transmission organizations, including PJM and SPP.
 
 
iv
 
·
The transition to market for generation in Ohio, including the implementation of ESPs.
·
Our ability to successfully and profitably manage our separate competitive generation assets.
·
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·
Actions of rating agencies, including changes in the ratings of our debt.
·
The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
·
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

The forward looking statements of AEP and its Registrant Subsidiaries speak only as of the date of this report or as of the date they are made.  AEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 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

Ohio Electric Security Plan Filing

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, 2014, OPCo’s net deferred fuel balance was $426 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.
 
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, 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.  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, 2014, OPCo’s incurred deferred capacity costs balance was $348 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.  The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% 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
 
 
1
 
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.

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.

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 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, our first quarter 2014 industrial sales volumes increased 2.2% over the first quarter 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.

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 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 

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
 
 
2
 
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 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.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a generation and distribution base rate biennial review 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 certain 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.

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

 
3
 
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 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.

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.

 
4
 
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 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 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 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.

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

 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs) 
APCo
 
Clinch River Plant, Unit 3
 
 
 235 
APCo
 
Glen Lyn Plant
 
 
 335 
APCo
 
Kanawha River Plant
 
 
 400 
APCo/AGR
 
Sporn Plant, Units 1-4
 
 
 600 
I&M
 
Tanners Creek Plant, Units 1-4
 
 
 995 
KPCo
 
Big Sandy Plant, Unit 2
 
 
 800 
AGR
 
Kammer Plant
 
 
 630 
AGR
 
Muskingum River Plant, Units 1-5
 
 
 1,440 
AGR
 
Picway Plant
 
 
 100 
PSO
 
Northeastern Station, Unit 4
 
 
 470 
SWEPCo
 
Welsh Plant, Unit 2
 
 
 528 
Total
 
 
 
 
 6,533 

As of March 31, 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 $974 million.
 
 
5
 
In addition, we are in the process of obtaining permits and other necessary regulatory approvals for either the conversion of some of our coal units to natural gas or installing emission control equipment on certain units.  The following table lists the 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
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs) 
KPCo
 
Big 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 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.  Nearly all of the states in which our power plants are located are covered by CAIR.

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) 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.

 
6
 
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, 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 was granted in June 2013.  Separate appeals of the supplemental rule, the Error Corrections Rule and the further revisions have been filed, but are being held in abeyance.

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

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  The effective date of the final rule was April 16, 2012 and compliance is required within three years.  We are participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed.  In 2012, the Federal EPA published a notice announcing that it would
 
 
7
 
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.

The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and allows operators to exclude periods of startup and shutdown from the emissions averaging periods.  The compliance time frame remains a serious concern.  A one-year administrative extension may be available if the extension is necessary for the installation of controls or to avoid a serious reliability problem.  In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades.  We are concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines.  We 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.

 
8
 
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.  In January 2014, the parties filed a motion with the court to establish December 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.

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 significant costs to upgrade or close and replace these existing facilities under the proposed solid waste management alternative.  Regulation of these materials as hazardous wastes would significantly increase these costs.  As the rule is not final, we are unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

Clean Water Act Regulations

In 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling.  Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority.  We are evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at our facilities.  In June 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments.  We submitted comments in July 2012.  Issuance of a final rule is expected in 2014.  We are preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

 
9
 
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 March 2014, the Federal EPA and the U.S. Army Corps of Engineers jointly announced that they will be issuing 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 of the proposed rule.  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.

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.”

 
10
 
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.

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 operation 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 months ended March 31, 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.
 
 
11
 
AEP CONSOLIDATED

First Quarter of 2014 Compared to First Quarter of 2013

Net Income increased from $364 million in 2013 to $561 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.


Our results of operations are discussed below by operating segment.

VERTICALLY INTEGRATED UTILITIES

 
 
 
Three Months Ended
 
 
 
 
March 31,
 
Vertically Integrated Utilities
 
2014 
 
2013 
 
 
 
 
(in millions)
 
Revenues
 
$
 2,586 
 
$
 2,515 
 
Fuel and Purchased Electricity
 
 
 1,094 
 
 
 1,201 
 
Gross Margin
 
 
 1,492 
 
 
 1,314 
 
Other Operation and Maintenance
 
 
 576 
 
 
 578 
 
Depreciation and Amortization
 
 
 263 
 
 
 235 
 
Taxes Other Than Income Taxes
 
 
 96 
 
 
 91 
 
Operating Income
 
 
 557 
 
 
 410 
 
Interest and Investment Income
 
 
 1 
 
 
 3 
 
Carrying Costs Income (Expense)
 
 
 (1)
 
 
 1 
 
Allowance for Equity Funds Used During Construction
 
 
 10 
 
 
 9 
 
Interest Expense
 
 
 (131)
 
 
 (136)
 
Income Before Income Tax Expense
 
 
 436 
 
 
 287 
 
Income Tax Expense
 
 
 157 
 
 
 106 
 
Net Income
 
$
 279 
 
$
 181 
 

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.
 
NM
Not meaningful.
 

 
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.  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.

 
13
 

First Quarter of 2014 Compared to First 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 

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 offset in Other Operation and Maintenance expenses 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.

 
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 million primarily due to an increase in pretax book income.

TRANSMISSION AND DISTRIBUTION UTILITIES

 
 
 
Three Months Ended
 
 
 
 
March 31,
 
Transmission and Distribution Utilities 
 
2014 
 
2013 
 
 
 
 
(in millions)
 
Revenues
 
$
 1,215 
 
$
 1,134 
 
Fuel and Purchased Electricity
 
 
 403 
 
 
 449 
 
Amortization of Generation Deferrals
 
 
 31 
 
 
 - 
 
Gross Margin
 
 
 781 
 
 
 685 
 
Other Operation and Maintenance
 
 
 293 
 
 
 244 
 
Depreciation and Amortization
 
 
 161 
 
 
 133 
 
Taxes Other Than Income Taxes
 
 
 119 
 
 
 104 
 
Operating Income
 
 
 208 
 
 
 204 
 
Interest and Investment Income
 
 
 3 
 
 
 1 
 
Carrying Costs Income
 
 
 7 
 
 
 3 
 
Allowance for Equity Funds Used During Construction
 
 
 3 
 
 
 2 
 
Interest Expense
 
 
 (70)
 
 
 (75)
 
Income Before Income Tax Expense
 
 
 151 
 
 
 135 
 
Income Tax Expense
 
 
 54 
 
 
 48 
 
Net Income
 
$
 97 
 
$
 87 
 

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.
 
NM
Not 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.  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.
 

 
16
 

First Quarter of 2014 Compared to First 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 

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 million primarily due to the following:
 
·
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.

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.

 
17
 
AEP TRANSMISSION HOLDCO

First Quarter of 2014 Compared to First Quarter of 2013

Net Income from our AEP Transmission Holdco segment increased from $12 million in 2013 to $24 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 
 
 
 
 
(in millions)
 
Revenues
 
$
 1,251 
 
$
 920 
 
Fuel, Purchased Electricity and Other
 
 
 805 
 
 
 568 
 
Gross Margin
 
 
 446 
 
 
 352 
 
Other Operation and Maintenance
 
 
 116 
 
 
 124 
 
Depreciation and Amortization
 
 
 57 
 
 
 62 
 
Taxes Other Than Income Taxes
 
 
 12 
 
 
 16 
 
Operating Income
 
 
 261 
 
 
 150 
 
Interest and Investment Income
 
 
 1 
 
 
 - 
 
Interest Expense
 
 
 (12)
 
 
 (19)
 
Income Before Income Tax Expense
 
 
 250 
 
 
 131 
 
Income Tax Expense
 
 
 87 
 
 
 46 
 
Net Income
 
$
 163 
 
$
 85 
 

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 

 
18
 

First Quarter of 2014 Compared to First 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 

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

·
Generation 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 million primarily due to an increase in pretax book income.

AEP RIVER OPERATIONS

First Quarter of 2014 Compared to First Quarter of 2013

Net Income from our AEP River Operations segment increased from a loss of $2 million in 2013 to income of $3 million in 2014, due to improvements in river conditions as well as improvements in grain export demand.

CORPORATE AND OTHER

First Quarter of 2014 Compared to First Quarter of 2013

Net Income from Corporate and Other decreased from income of $1 million in 2013 to a loss of $5 million in 2014 primarily due to an increase in net interest.

 
19
 
AEP SYSTEM INCOME TAXES

First Quarter of 2014 Compared to First Quarter of 2013

Income Tax Expense increased $112 million primarily due to an increase in pretax book income.

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

 
 
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 declined from 54.3% as of December 31, 2013 to 54.2% as of March 31, 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, 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, 2014, our available liquidity was approximately $3 billion as illustrated in the table below:

 
 
 
Amount
 
 
Maturity
 
 
 
(in millions)
 
 
 
Commercial Paper Backup:
 
 
 
 
 
 
 
Revolving Credit Facility
 
$
 1,750 
 
 
June 2016
 
Revolving Credit Facility
 
 
 1,750 
 
 
July 2017
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 
 
 
 

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

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, 2014, the maximum future payment for letters of credit issued under the uncommitted facility was $75 million with a maturity in July 2014.  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 million from bank conduits to purchase receivables.  A commitment of $385 million 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.

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, 2014, this contractually-defined percentage was 50.6%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  As of March 31, 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, 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 April 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,
 
 
 
2014 
 
2013 
 
 
 
(in millions)
Cash and Cash Equivalents at Beginning of Period
 
$
 118 
 
$
 279 
Net Cash Flows from Operating Activities
 
 
 1,133 
 
 
 756 
Net Cash Flows Used for Investing Activities
 
 
 (981)
 
 
 (772)
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 End of Period
 
$
 292 
 
$
 179 

Cash from operations and short-term borrowings provides working capital and allows us to meet other short-term cash needs.
 
Operating Activities
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
 
 
March 31,
 
 
 
2014 
 
2013 
 
 
 
(in millions)
Net Income
 
$
 561 
 
$
 364 
Depreciation and Amortization
 
 
 491 
 
 
 420 
Other
 
 
 81 
 
 
 (28)
Net Cash Flows from Operating Activities
 
$
 1,133 
 
$
 756 

Net Cash Flows from Operating Activities were $1.1 billion in 2014 consisting primarily of Net Income of $561 million and $491 million of noncash Depreciation and Amortization partially offset by $137 million of fuel cost deferrals and $56 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 in 2013 consisting primarily of Net Income of $364 million and $420 million of noncash Depreciation and Amortization.  Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Net cash outflows for Accrued Taxes were a result of recording the estimated federal tax loss for tax/book temporary differences.
 
 
22
 
Investing Activities
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
 
 
March 31,
 
 
 
2014 
 
2013 
 
 
 
(in millions)
Construction Expenditures
 
$
 (907)
 
$
 (843)
Acquisitions of Nuclear Fuel
 
 
 (49)
 
 
 (47)
Acquisitions of Assets/Businesses
 
 
 (43)
 
 
 (2)
Insurance Proceeds Related to Cook Plant Fire
 
 
 - 
 
 
 72 
Other
 
 
 18 
 
 
 48 
Net Cash Flows Used for Investing Activities
 
$
 (981)
 
$
 (772)

Net Cash Flows Used for Investing Activities were $981 million 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 in 2013 primarily due to Construction Expenditures for environmental, distribution and transmission investments.
 
Financing Activities
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
 
 
March 31,
 
 
 
2014 
 
2013 
 
 
 
(in millions)
Issuance of Common Stock, Net
 
$
 15 
 
$
 15 
Issuance of Debt, Net
 
 
 281 
 
 
 139 
Dividends Paid on Common Stock
 
 
 (245)
 
 
 (230)
Other
 
 
 (29)
 
 
 (8)
Net Cash Flows from (Used for) Financing Activities
 
$
 22 
 
$
 (84)

Net Cash Flows from Financing Activities in 2014 were $22 million.  Our net debt issuances were $281 million. The net issuances included issuances of $76 million of other debt notes and an increase in short-term borrowing of $575 million offset by retirements of $258 million of senior unsecured and other debt notes and $112 million of securitization bonds.  We paid common stock dividends of $245 million.  See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows Used for Financing Activities in 2013 were $84 million.  Our net debt issuances were $139 million. The net issuances included issuances of $475 million of senior unsecured notes, a $200 million draw on a $1 billion term credit facility and an increase in short-term borrowing of $326 million offset by retirements of $753 million of senior unsecured and other debt notes and $105 million of securitization bonds.  We paid common stock dividends of $230 million.

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

BUDGETED CONSTRUCTION EXPENDITURES

In April 2014, we increased our forecast for construction expenditures by $250 million to approximately $4.1 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 
 
 
 
(in millions)
Rockport Plant, Unit 2 Future Minimum Lease Payments
 
$
 1,330 
 
$
 1,330 
Railcars Maximum Potential Loss from Lease Agreement
 
 
 19 
 
 
 19 

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 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.

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.

 
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.

 
25
 
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
 
Distribution
and
 
 
 
Utilities
 
Utilities
Marketing
Total
 
 
(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 

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

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

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.

 
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, 2014, our credit exposure net of collateral to sub investment grade counterparties was approximately 9.2%, 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, 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
 
 
Counterparties
of
 
 
Credit
Credit
Net
>10% of
Counterparties
Counterparty Credit Quality
Collateral
Collateral
Exposure
Net Exposure
>10%
 
 
 
(in millions, except number of counterparties)
Investment Grade
 
$
 528 
 
$
 10 
 
$
 518 
 
 
 2 
 
$
 256 
Split Rating
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Noninvestment Grade
 
 
 1 
 
 
 1 
 
 
 - 
 
 
 - 
 
 
 - 
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 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total as of December 31, 2013
 
$
 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, 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
End
  
High
  
Average
  
Low
  
End
  
High
  
Average
  
Low
(in millions)
  
(in millions)
$
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.

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

 
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.

 
30
 


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.

 
31
 


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 Authorized
600,000,000 
 
600,000,000 
 
 
 
 
 
 
 
 
Shares Issued
508,397,086 
 
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.

 
33
 


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.

 
34
 

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

 
Page
 
Number
   
Significant Accounting Matters
 36
New Accounting Pronouncement
 37
Comprehensive Income
 37
Rate Matters
 39
Commitments, Guarantees and Contingencies
 46
Benefit Plans
 49
Business Segments
 50
Derivatives and Hedging
 52
Fair Value Measurements
 58
Income Taxes
 65
Financing Activities
 66
Variable Interest Entities
 68

 
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 months ended March 31, 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, 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.
 
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 presents our basic and diluted EPS calculations included on our condensed statements of income:

 
 
 
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 

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

 
36
 
2.  NEW ACCOUNTING PRONOUNCEMENT

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 pronouncement 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 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.

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.

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)

 
37
 
Reclassifications from Accumulated Other Comprehensive Income

The following table provides 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.

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 

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

 
38
 
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 Recovered
 
 
 
 
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 
 
 
 - 
 
Expanded Net Energy Charge - Coal Inventory
 
 
 19 
 
 
 21 
 
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 

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
 
 
39
 
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.  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% 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, 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.  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.  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.

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 SEET filing 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 with the PUCO.  In April 2014, OPCo entered into a stipulation agreement with 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 2012 SEET filing is scheduled for April 2014.  Management does not believe that there were significantly excessive earnings in 2013 for OPCo.

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 with the effective date as 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 approval 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.  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.

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.

 
41
 
In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges, which, if ordered, would be $35 million plus carrying charges.  If the Supreme Court of Ohio ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC).  The PUCO subsequently ruled 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.

2012 – 2013 Fuel Adjustment Clause Audits
 
In April 2014, the PUCO-selected outside consultant provided its preliminary draft report related to their 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013.  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 bankruptcy and shut down operations effective immediately.  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 recommends 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.  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.  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 for 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, 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, 2014, the net book value of Welsh Plant, Unit 2 was $86 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.  This order became final and appealable in April 2014.

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, SWEPCo filed an application to implement its initial transmission cost recovery factor (TCRF) requesting additional annual revenue of $10 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 March 2014, the Administrative Law Judge (ALJ) dismissed this case without prejudice.  The ALJ concluded that SWEPCo’s application was premature as the PUCT had not completed its ruling on the motions for rehearing 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.

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.

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.  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.  Upon transfer of the Mitchell Plant to WPCo, WPCo will no longer purchase power from AGR.

APCo IGCC Plant

As of March 31, 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.  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 generation and distribution base rate biennial review 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 certain 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.

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 2014, OCC Staff 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
 
 
44
 
recommendations did not support the advanced metering rider or the expansion of the transmission rider.  A hearing at the OCC is scheduled for June 2014.  If the OCC were to disallow any portion of this base rate request, 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, 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.  If any part of the IURC order is overturned by the Indiana Supreme Court, it could reduce future net income and cash flows.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its 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, 2014, I&M has incurred costs of $405 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 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 Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015.  Upon the retirement of the Tanners Creek Plant, I&M proposes that 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.  The new depreciation rates are expected to result in a decrease in I&M’s Michigan jurisdictional electric depreciation expense which I&M proposes to implement in the month following a MPSC order in the revised depreciation case.  A hearing at the MPSC is scheduled for September 2014.

 
45
 
As of March 31, 2014, the net book value of the Tanners Creek Plant was $334 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.

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, 2014, the net book value of Big Sandy Plant, Unit 2 was $247 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.  If any part of the KPSC order is overturned, it could reduce future net income and cash flows and impact financial condition.

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
 
 
46
 
of credit.  As of March 31, 2014, the maximum future payments for letters of credit issued under the revolving credit facilities were $130 million with maturities ranging from June 2014 to April 2015.

In January 2014, we issued letters of credit under an $85 million uncommitted facility signed in October 2013.  As of March 31, 2014, the maximum future payment for letters of credit issued under the uncommitted facility was $75 million with a maturity in July 2014.  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 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $356 million.  The letters of credit have maturities ranging from July 2014 to March 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, 2014, SWEPCo has collected approximately $62 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 million is recorded in Asset Retirement Obligations on our condensed balance sheets.

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

Indemnifications and Other Guarantees

Contracts

We enter into several types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, our exposure generally does not exceed the sale price.  As of March 31, 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, 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 is accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $13 million and $15 million for
 
 
47
 
I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 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 approximately $8 million.  As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ.  We cannot predict the amount of additional cost, if any.

NUCLEAR CONTINGENCIES

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

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
 
 
48
 
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.  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.

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.  We will continue to defend the case.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

6.  BENEFIT PLANS

Components of Net Periodic Benefit Cost

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

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended March 31,
 
Three Months Ended March 31,
 
2014 
 
2013 
 
2014 
 
2013 
 
(in millions)
Service Cost
$
 18 
 
$
 17 
 
$
 4 
 
$
 6 
Interest Cost
 
 55 
 
 
 50 
 
 
 17 
 
 
 18 
Expected Return on Plan Assets
 
 (66)
 
 
 (69)
 
 
 (28)
 
 
 (27)
Amortization of Prior Service Cost (Credit)
 
 1 
 
 
 1 
 
 
 (17)
 
 
 (17)
Amortization of Net Actuarial Loss
 
 31 
 
 
 46 
 
 
 5 
 
 
 16 
Net Periodic Benefit Cost (Credit)
$
 39 
 
$
 45 
 
$
 (19)
 
$
 (4)

 
49
 
7.  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 operation 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’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

 
50
 
The tables below present our reportable segment information for the three months ended March 31, 2014 and 2013 and balance sheet information as of March 31, 2014 and December 31, 2013.  These amounts include certain estimates and allocations where necessary.

 
 
 
 
 
 
 
Transmission
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vertically
 
and
 
AEP
 
Generation
 
 
 
 
Corporate
 
 
 
 
 
 
 
 
 
 
Integrated
 
Distribution
 
Transmission
 
&
 
AEP River
and Other
Reconciling
 
 
 
 
 
 
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 River
and Other
Reconciling
 
 
 
 
 
 
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

(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’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’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’s investments in subsidiary companies.

 
51
 
8.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

We are exposed to certain market risks as a major power producer and marketer of wholesale electricity, 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, 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

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 months ended March 31, 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 of March 31, 2014, these contracts will be grouped as “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’s term and at the time a contract settles.  Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with our estimates of current market consensus for forward prices in the current period.  This is particularly true for longer term contracts.  Cash flows may vary based on market conditions, margin requirements and the timing of settlement of our risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the March 31, 2014 and December 31, 2013 condensed balance sheets, we netted $19 million and $4 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $17 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, 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
 
Liabilities
Financial
 
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 

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

The table below presents our activity of derivative risk management contracts for the three months ended March 31, 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 

(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 months ended March 31, 2014, we recognized gains of $2 million on our hedging instruments and offsetting losses of $2 million on our long-term debt.  During the three months ended March 31, 2013, we recognized losses of $1 million on our hedging instruments and offsetting gains of $1 million on our long-term debt.  During the three months ended March 31, 2014 and 2013, hedge ineffectiveness was immaterial.

Accounting for Cash Flow Hedging Strategies

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

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on our condensed balance sheets, depending on the specific nature of the risk being hedged.  During the three months ended March 31, 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 months ended March 31, 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 months ended March 31, 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 months ended March 31, 2014 and 2013, we did not designate any foreign currency derivatives as cash flow hedges.

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

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 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)

(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, 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 41 months.

 
56
 
Credit Risk

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

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

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs), 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, 2014 and December 31, 2013:

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

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

 
57
 
9.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

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

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

 
59
 
The following table provides the activity for our fixed income and equity securities within Other Temporary Investments for the three months ended March 31, 2014 and 2013:

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

As of March 31, 2014 and December 31, 2013, we had no Other Temporary Investments with an unrealized loss position.  As of March 31, 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 months ended March 31, 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.

 
60
 
The following is a summary of nuclear trust fund investments as of March 31, 2014 and December 31, 2013:

 
 
 
March 31, 2014
 
December 31, 2013
 
 
 
Estimated
 
Gross
 
Other-Than-
 
Estimated
 
Gross
 
Other-Than-
 
 
Fair
Unrealized
Temporary
Fair
Unrealized
Temporary
 
 
Value
Gains
Impairments
Value
Gains
Impairments
 
 
 
(in millions)
Cash and Cash Equivalents
 
$
 12 
 
$
 - 
 
$
 - 
 
$
 19 
 
$
 - 
 
$
 - 
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)
Equity Securities - Domestic
 
 
 1,020 
 
 
 514 
 
 
 (80)
 
 
 1,012 
 
 
 506 
 
 
 (82)
Spent Nuclear Fuel and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning Trusts
 
$
 1,962 
 
$
 550 
 
$
 (85)
 
$
 1,932 
 
$
 535 
 
$
 (87)

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

 
Three Months Ended March 31,
 
2014 
 
2013 
 
(in millions)
Proceeds from Investment Sales
$
 148 
 
$
 168 
Purchases of Investments
 
 164 
 
 
 185 
Gross Realized Gains on Investment Sales
 
 8 
 
 
 3 
Gross Realized Losses on Investment Sales
 
 1 
 
 
 2 

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

 
61
 
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, 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 

 
62
 


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 

(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, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $2 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $32 million in 2014, $56 million in periods 2015-2017, $8 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $15 million in 2014, $49 million in periods 2015-2017, $16 million in periods 2018-2019 and $23 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) million in periods 2015-2017 and $(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 months ended March 31, 2014 and 2013.

 
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, 2014
 
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)
 
 
 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 

 
 
 
Net Risk Management
Three Months Ended March 31, 2013
 
Assets (Liabilities)
 
 
 
(in millions)
Balance as of December 31, 2012
 
$
 86 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
 
 (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 

(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.

 
64
 
The following tables quantify the significant unobservable inputs used in developing the fair value of our Level 3 positions as of March 31, 2014 and December 31, 2013:

Significant Unobservable Inputs
March 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
 
Input/Range
 
Assets
 
Liabilities
Technique
Unobservable 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
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
 
Input/Range
 
Assets
 
Liabilities
Technique
Unobservable 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 
 
 
 
 
 
 
 
 
 
 

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

10.  INCOME TAXES

AEP System Tax Allocation Agreement

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

Federal and State Income Tax Audit Status

The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013.  The 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.

 
65
 
11.  FINANCING ACTIVITIES

Long-term Debt

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

Type of Debt
 
March 31, 2014
 
December 31, 2013
 
 
(in millions)
Senior Unsecured Notes
 
$
 11,571 
 
$
 11,799 
Pollution Control Bonds
 
 
 1,932 
 
 
 1,932 
Notes Payable
 
 
 342 
 
 
 369 
Securitization Bonds
 
 
 2,574 
 
 
 2,686 
Spent Nuclear Fuel Obligation (a)
 
 
 265 
 
 
 265 
Other Long-term Debt
 
 
 1,434 
 
 
 1,360 
Fair Value of Interest Rate Hedges
 
 
 (7)
 
 
 (9)
Unamortized Discount, Net
 
 
 (24)
 
 
 (25)
Total Long-term Debt Outstanding
 
 
 18,087 
 
 
 18,377 
Long-term Debt Due Within One Year
 
 
 1,612 
 
 
 1,549 
Long-term Debt
 
$
 16,475 
 
$
 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, 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 three months of 2014 are shown in the tables below:

 
 
 
 
 
Principal
 
 
Interest
 
 
Company
 
Type of Debt
 
Amount
 
 
Rate
 
Due Date
Issuances:
 
 
(in millions)
 
(%)
 
 
PSO
 
Other Long-term Debt
 
$
 50 
 
 
Variable
 
2016 
 
 
 
 
 
 
 
 
 
 
 
 
Non-Registrant:
 
 
 
 
 
 
 
 
 
 
Transource Missouri
 
Other Long-term Debt
 
 
 27 
 
 
Variable
 
2018 
Total Issuances
 
 
 
$
 77 
(a)
 
 
 
 
                     
       
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)
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.

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

As of March 31, 2014, trustees held on our behalf, $500 million of our reacquired Pollution Control Bonds.

Dividend Restrictions

Parent Restrictions

The holders of our common stock are entitled to receive the dividends declared by our Board of Directors provided funds are legally available for such dividends.  Our income 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 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
Type of Debt
Amount
Rate (a)
 
Amount
Rate (a)
 
 
(in millions)
 
 
 
 
(in millions)
 
 
 
Securitized Debt for Receivables (b)
 
$
 700 
 
 0.24 
%
 
$
 700 
 
 0.23 
%
Commercial Paper
 
 
 632 
 
 0.31 
%
 
 
 57 
 
 0.29 
%
Total Short-term Debt
 
$
 1,332 
 
 
 
 
$
 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.

 
67
 
Our receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables.  A commitment of $385 million 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.

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 
 

 
 
 
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 

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

12.  VARIABLE INTEREST ENTITIES

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

We are the primary beneficiary of Sabine, DCC Fuel, AEP Credit, Transition Funding, 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, 2014 and 2013 were $39 million and $44 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on the condensed balance sheets.

 
68
 
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, 2014 and 2013 were $25 million and $26 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 Receivables – AEP Credit” section of Note 11.

Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.  Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant.  Therefore, TCC is required to consolidate Transition Funding.  The securitized bonds totaled $2 billion and $2 billion as of March 31, 2014 and December 31, 2013, respectively.  Transition Funding has securitized transition assets of $1.8 billion and $1.9 billion as of March 31, 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-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, 2014 and December 31, 2013, respectively.  Ohio Phase-in-Recovery Funding has securitized assets of $127 million and $132 million as of March 31, 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
 
 
69
 
$380 million as of March 31, 2014 and December 31, 2013, respectively.  Appalachian Consumer Rate Relief Funding has securitized assets of $365 million and $369 million as of March 31, 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 table 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 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, 2014 and 2013 was $16 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.  In January 2014, Transource Missouri acquired transmission assets from the non-controlling owner and issued debt and received capital contributions to fund the acquisition.  The majority of Transource Energy’s activity resulted from the asset acquisition, debt issuance and capital contribution.  See the table below for the classification of Transource Energy’s assets and liabilities on the condensed balance sheets.

 
70
 
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
 
 
 
Sabine
DCC Fuel
Credit
Funding
 
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 

(a)
Includes an intercompany item eliminated in consolidation of $81 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
 
 
Sabine
DCC Fuel
Credit
Funding
 
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 million.
(c) Includes an intercompany item eliminated in consolidation of $4 million.
 
 
71
 
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, 2014 and 2013 were $2 million and $18 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
 
Maximum
 
 
the Balance Sheet
Exposure
 
the Balance Sheet
 
Exposure
 
 
(in millions)
Capital Contribution from SWEPCo
 
$
 8 
 
$
 8 
 
$
 8 
 
$
 8 
Retained Earnings
 
 
 2 
 
 
 2 
 
 
 1 
 
 
 1 
SWEPCo's Guarantee of Debt
 
 
 - 
 
 
 85 
 
 
 - 
 
 
 61 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Investment in DHLC
 
$
 10 
 
$
 95 
 
$
 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.

In August 2012, the PJM board cancelled the PATH Project, our transmission joint venture with FirstEnergy, and removed it from the 2012 Regional Transmission Expansion Plan.  In 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’s abandonment cost recovery application, subject to settlement procedures and hearing.  The parties to the case have been unable to reach a settlement agreement.  In March 2014, the settlement judge recommended termination of the settlement proceedings and this case is expected to proceed to a hearing.

Our investment in PATH-WV was:

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

As of March 31, 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.
 
 
72
 
 
APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

 
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.  Upon transfer of the Mitchell Plant to WPCo, WPCo will no longer purchase power from AGR.
 
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.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a generation and distribution base rate biennial review 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 certain 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.

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.  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.
 
 
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 

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)
 
 1,715 
 
 
 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.

 
75
 

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
 
 
 
 
$
 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 

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

·
Retail Margins increased $35 million primarily due to the following:
 
·
A $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 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 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.

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.

 
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.

 
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.
 
 
 

 
80
 


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
 
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

 
84
 

 
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES


 
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, 2014, I&M has incurred costs of $405 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 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 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.  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 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 186 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 

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)
 
 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.

 
87
 

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
 
 
 
 
$
 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 

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 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.
 
Expenses and Other and Income Tax Expense changed between years as follows:
 
·  Other Operation and Maintenance expenses decreased $1 million primarily due to the following:
  · A $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
 
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.

 
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.

 
91
 


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
 
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

 
96
 

 
OHIO POWER COMPANY AND SUBSIDIARIES


 
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 Filing

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, 2014, OPCo’s net deferred fuel balance was $426 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.

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, 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.  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, 2014, OPCo’s incurred deferred capacity costs balance was $348 million, including debt carrying costs.

 
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 ordered OPCo to conduct energy-only auctions for an additional 50% 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 Matters
APCo, I&M, OPCo, PSO, SWEPCo
   133
New Accounting Pronouncement
APCo, I&M, OPCo, PSO, SWEPCo
   133
Comprehensive Income
APCo, I&M, OPCo, PSO, SWEPCo
   134
Rate Matters
APCo, I&M, OPCo, PSO, SWEPCo
   141
Commitments, Guarantees and Contingencies
APCo, I&M, OPCo, PSO, SWEPCo
   149
Benefit Plans
APCo, I&M, OPCo, PSO, SWEPCo
   152
Business Segments
APCo, I&M, OPCo, PSO, SWEPCo
   153
Derivatives and Hedging
APCo, I&M, OPCo, PSO, SWEPCo
   154
Fair Value Measurements
APCo, I&M, OPCo, PSO, SWEPCo
   166
Income Taxes
APCo, I&M, OPCo, PSO, SWEPCo
   177
Financing Activities
APCo, I&M, OPCo, PSO, SWEPCo
   178
Variable Interest Entities
APCo, 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 

 
138
 
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.

 
140
 
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 

 
141
 
 
 
 
 
 
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% 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, 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.  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.  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.

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 SEET filing 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 with the PUCO.  In April 2014, OPCo entered into a stipulation agreement with 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 2012 SEET filing is scheduled for April 2014.  Management does not believe that there were significantly excessive earnings in 2013 for OPCo.

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 with the effective date as 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 approval 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.  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.

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.

 
144
 
In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges, which, if ordered, would be $35 million plus carrying charges.  If the Supreme Court of Ohio ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC).  The PUCO subsequently ruled 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.

2012 – 2013 Fuel Adjustment Clause Audits

In April 2014, the PUCO-selected outside consultant provided its preliminary draft report related to their 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013.  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 bankruptcy and shut down operations effective immediately.  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 recommends 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.  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.  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 for 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.

 
145
 
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, 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, 2014, the net book value of Welsh Plant, Unit 2 was $86 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.  This order became final and appealable in April 2014.

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, SWEPCo filed an application to implement its initial transmission cost recovery factor (TCRF) requesting additional annual revenue of $10 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 March 2014, the Administrative Law Judge (ALJ) dismissed this case without prejudice.  The ALJ concluded that SWEPCo’s application was premature as the PUCT had not completed its ruling on the motions for rehearing 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.

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
 
 
146
 
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.

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 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.  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.  Upon transfer of the Mitchell Plant to WPCo, WPCo will no longer purchase power from AGR.

APCo IGCC Plant

As of March 31, 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.  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 generation and distribution base rate biennial review 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 certain 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.

 
147
 
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 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 2014, OCC Staff 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 recommendations did not support the advanced metering rider or the expansion of the transmission rider.  A hearing at the OCC is scheduled for June 2014.  If the OCC were to disallow any portion of this base rate request, 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, 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.  If any part of the IURC order is overturned by the Indiana Supreme Court, it could reduce future net income and cash flows.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its 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, 2014, I&M has incurred costs of $405 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
 
 
148
 
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 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 Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015.  Upon the retirement of the Tanners Creek Plant, I&M proposes that 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.  The new depreciation rates are expected to result in a decrease in I&M’s Michigan jurisdictional electric depreciation expense which I&M proposes to implement in the month following a MPSC order in the revised depreciation case.  A hearing at the MPSC is scheduled for September 2014.

As of March 31, 2014, the net book value of the Tanners Creek Plant was $334 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.

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 SWEPCo

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

 
149
 
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, 2014, the maximum future payments for letters of credit issued under the revolving credit facilities were as follows:

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

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
 
 
(in thousands)
 
 
APCo
 
$
229,650 
 
$
 232,293 
 
March 2016 to March 2017 
I&M
 
 
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, 2014, SWEPCo has collected approximately $62 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 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed balance sheets.

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

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

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of March 31, 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
 
 
150
 
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, 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
Company
 
Potential Loss
 
 
(in thousands)
APCo
 
$
 3,772 
I&M
 
 
 2,580 
OPCo
 
 
 4,384 
PSO
 
 
 1,347 
SWEPCo
 
 
 2,486 

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignments are accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $13 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 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.

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 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
 
 
151
 
requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S.  Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

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.  The motion to dismiss, 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.

In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action.  Management will continue to defend the case.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

6.  BENEFIT PLANS

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

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three months ended March 31, 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 

 
152
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
Three Months Ended March 31,
 
Three Months Ended March 31,
 
2014 
 
2013 
 
2014 
 
2013 
 
(in thousands)
Service Cost
$
 2,517 
 
$
 2,184 
 
$
 487 
 
$
 805 
Interest Cost
 
 6,573 
 
 
 6,025 
 
 
 1,909 
 
 
 2,055 
Expected Return on Plan Assets
 
 (7,748)
 
 
 (8,207)
 
 
 (3,364)
 
 
 (3,296)
Amortization of Prior Service Cost (Credit)
 
 49 
 
 
 49 
 
 
 (2,355)
 
 
 (2,355)
Amortization of Net Actuarial Loss
 
 3,646 
 
 
 5,422 
 
 
 592 
 
 
 1,882 
Net Periodic Benefit Cost (Credit)
$
 5,037 
 
$
 5,473 
 
$
 (2,731)
 
$
 (909)

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 

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)

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.  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.

 
153
 
8.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, 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.

 
154
 
The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of March 31, 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
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 - 

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 months ended March 31, 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 of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities.  The Registrant Subsidiaries do not hedge all fuel price risk.

 
155
 
AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure.  Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate.  AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt.  The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures.  The Registrant Subsidiaries do not hedge all interest rate exposure.

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

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

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

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

According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the March 31, 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 
 
 
156
 
The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of March 31, 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 

(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.

 
161
 

The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three months ended March 31, 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.

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 months ended March 31, 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 months ended March 31, 2014 and 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 months ended March 31, 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.

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 months ended March 31, 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 months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges.

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

 
163
 

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 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)

 
 
 
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
 
 
 
 
 
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.

 
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, 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
Company
 
Downgrade Triggers
 
Required to Post
 
Activities
 
 
 
(in thousands)
APCo
 
$
 285 
 
$
 5,254 
 
$
 4,774 
I&M
 
 
 190 
 
 
 3,560 
 
 
 3,238 
OPCo
 
 
 78 
 
 
 - 
 
 
 - 
PSO
 
 
 132 
 
 
 4,156 
 
 
 - 
SWEPCo
 
 
 167 
 
 
 145 
 
 
 - 

 
 
 
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, 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
Company
 
Netting Arrangements
 
Collateral Posted
 
is Triggered
 
 
 
(in thousands)
APCo
 
$
 16,375 
 
$
 - 
 
$
 12,865 
I&M
 
 
 11,107 
 
 
 - 
 
 
 8,726 
OPCo
 
 
 - 
 
 
 - 
 
 
 - 
PSO
 
 
 - 
 
 
 - 
 
 
 - 
SWEPCo
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 

9.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

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

 
166
 
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 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, 2014 and December 31, 2013 are summarized in the following table:

 
 
March 31, 2014
 
December 31, 2013
Company
 
Book Value
 
Fair Value
 
Book Value
 
Fair Value
 
 
(in thousands)
APCo
 
$
 4,194,516 
 
$
 4,730,819 
 
$
 4,194,357 
 
$
 4,587,079 
I&M
 
 
 2,012,844 
 
 
 2,203,640 
 
 
 2,039,016 
 
 
 2,174,891 
OPCo
 
 
 2,510,285 
 
 
 2,869,364 
 
 
 2,735,175 
 
 
 3,007,191 
PSO
 
 
 1,049,793 
 
 
 1,200,741 
 
 
 999,810 
 
 
 1,111,149 
SWEPCo
 
 
 2,041,796 
 
 
 2,277,262 
 
 
 2,043,332 
 
 
 2,214,730 

 
167
 
Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

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

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

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

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

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

 
 
 
March 31, 2014
 
December 31, 2013
 
 
 
Estimated
 
Gross
 
Other-Than-
 
Estimated
 
Gross
 
Other-Than-
 
 
Fair
Unrealized
Temporary
Fair
Unrealized
Temporary
 
 
Value
Gains
Impairments
Value
Gains
Impairments
 
 
 
(in thousands)
Cash and Cash Equivalents
 
$
 12,439 
 
$
 - 
 
$
 - 
 
$
 18,804 
 
$
 - 
 
$
 - 
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)
Equity Securities - Domestic
 
 
 1,020,145 
 
 
 513,803 
 
 
 (79,563)
 
 
 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)

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

 
Three Months Ended March 31,
 
2014 
 
2013 
 
(in thousands)
Proceeds from Investment Sales
$
 147,700 
 
$
 167,670 
Purchases of Investments
 
 164,511 
 
 
 184,299 
Gross Realized Gains on Investment Sales
 
 8,141 
 
 
 3,323 
Gross Realized Losses on Investment Sales
 
 874 
 
 
 2,315 

 
168
 
The adjusted cost of fixed income securities was $894 million and $872 million as of March 31, 2014 and December 31, 2013, respectively.  The adjusted cost of equity securities was $506 million and $506 million as of March 31, 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, 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 

 
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, 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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 

 
170
 


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 

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)
 
$
 - 

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)
 
$
 - 

 
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 

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 

 
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)
 
$
 - 

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” 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 associated cash collateral under the accounting guidance for “Derivatives and 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 months ended March 31, 2014 and 2013.
 
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:

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 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 
 
$
 - 
 
$
 - 

(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.

 
175
 
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of March 31, 2014 and December 31, 2013:

Significant Unobservable Inputs
March 31, 2014
APCo
 
 
 
  
 
 
 
 
 
 
  
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
  
Forward Price Range
 
Assets
  
Liabilities
Technique
Unobservable 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
  
Liabilities
Technique
Unobservable 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
March 31, 2014
I&M
 
 
 
  
 
 
 
 
 
 
  
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
  
Forward Price Range
 
Assets
  
Liabilities
Technique
Unobservable 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
  
Liabilities
Technique
Unobservable 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 
 
 
 
 
  
 
 
 
 
 

 
176
 
Significant Unobservable Inputs
March 31, 2014
OPCo
 
 
 
  
 
 
 
 
 
 
  
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
  
Forward Price Range
 
Assets
  
Liabilities
Technique
Unobservable Input (a)
  
Low
 
High
 
 
(in thousands)
 
 
 
 
  
 
 
 
 
 
Energy Contracts
 
$
 - 
  
$
 - 
 
Discounted Cash Flow 
 
Forward Market Price 
  
$
 - 
 
$
 - 
FTRs
 
 
 3,990 
  
 
 78 
 
Discounted Cash Flow 
 
Forward Market Price 
  
 
 (5.05)
 
 
 9.17 
Total
 
$
 3,990 
  
$
 78 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
  
 
 
 
 
 
Significant Unobservable Inputs
December 31, 2013
OPCo
 
 
 
  
 
 
 
 
 
 
  
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
  
Forward Price Range
 
Assets
  
Liabilities
Technique
Unobservable 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
  
Liabilities
Technique
Unobservable 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
March 31, 2014
SWEPCo
 
 
 
  
 
 
 
 
 
 
  
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
  
Forward Price Range
 
Assets
  
Liabilities
Technique
Unobservable 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 
 
 
 
 
  
 
 
 
 
 

(a)
Represents market prices in dollars per MWh.

10.  INCOME TAXES

AEP System Tax Allocation Agreement

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

 
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.

11.  FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first three months of 2014 are shown in the tables below:

 
 
 
 
Principal
 
Interest
 
 
Company
 
Type of Debt
 
Amount (a)
 
Rate
 
Due Date
Issuances:
 
 
 
(in thousands)
 
(%)
 
 
PSO
 
Other Long-term Debt
 
$
 50,000 
 
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.

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

As of March 31, 2014, trustees held on behalf of I&M and OPCo, $40 million and $460 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.

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, 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 three months ended March 31, 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
 
 
(in thousands)
APCo
 
$
 - 
 
$
 249,630 
 
$
 - 
 
$
 164,681 
 
$
 245,516 
 
$
 600,000 
I&M
 
 
 - 
 
 
 158,857 
 
 
 - 
 
 
 92,303 
 
 
 59,162 
 
 
 500,000 
OPCo
 
 
 55,640 
 
 
 405,350 
 
 
 25,930 
 
 
 135,747 
 
 
 (27,108)
 
 
 600,000 
PSO
 
 
 121,100 
 
 
 - 
 
 
 58,500 
 
 
 - 
 
 
 (70,119)
 
 
 300,000 
SWEPCo
 
 
 130,258 
 
 
 - 
 
 
 61,132 
 
 
 - 
 
 
 (117,342)
 
 
 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,
 
 
2014 
 
2013 
Maximum Interest Rate
 
 0.33 
%
 
 0.43 
%
Minimum Interest Rate
 
 0.28 
%
 
 0.35 
%

 
179
 
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 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,
Company
 
2014 
 
2013 
2014 
 
2013 
APCo
 
 - 
%
 
 0.38 
%
 
 0.31 
%
 
 0.37 
%
I&M
 
 - 
%
 
 0.36 
%
 
 0.31 
%
 
 0.37 
%
OPCo
 
 0.31 
%
 
 0.36 
%
 
 0.29 
%
 
 0.37 
%
PSO
 
 0.31 
%
 
 0.36 
%
 
 - 
%
 
 0.38 
%
SWEPCo
 
 0.31 
%
 
 - 
%
 
 - 
%
 
 0.38 
%

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 million from bank conduits to purchase receivables.  A commitment of $385 million 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.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of March 31, 2014 and December 31, 2013 was as follows:

 
 
 
March 31,
 
December 31,
Company
 
2014 
 
2013 
 
 
 
(in thousands)
APCo
 
$
 175,738 
 
$
 156,599 
I&M
 
 
 154,510 
 
 
 139,257 
OPCo
 
 
 350,735 
 
 
 324,287 
PSO
 
 
 111,522 
 
 
 115,260 
SWEPCo
 
 
 145,648 
 
 
 149,337 

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

 
 
 
Three Months Ended March 31,
Company
 
2014 
 
2013 
 
 
 
(in thousands)
APCo
 
$
 2,423 
 
$
 1,556 
I&M
 
 
 2,040 
 
 
 1,452 
OPCo
 
 
 7,498 
 
 
 4,669 
PSO
 
 
 1,323 
 
 
 1,414 
SWEPCo
 
 
 1,566 
 
 
 1,380 

 
180
 
The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:

 
 
 
Three Months Ended March 31,
Company
 
2014 
 
2013 
 
 
 
(in thousands)
APCo
 
$
 437,196 
 
$
 398,193 
I&M
 
 
 407,150 
 
 
 351,830 
OPCo
 
 
 686,627 
 
 
 696,958 
PSO
 
 
 290,217 
 
 
 240,275 
SWEPCo
 
 
 390,588 
 
 
 331,936 

12.  VARIABLE INTEREST ENTITIES

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

SWEPCo is the primary beneficiary of Sabine.  I&M is the primary beneficiary of DCC Fuel.  OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding.  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, 2014 and 2013 were $39 million and $44 million, respectively.  See the tables 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 

 
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, 2014 and 2013 were $25 million and $26 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 

Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Phase-in recovery property.  Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant.  Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding.  The securitized bonds totaled $267 million and $267 million as of March 31, 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 million and $132 million as of March 31, 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.

 
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 

 
(a)
Includes an intercompany item eliminated in consolidation as of March 31, 2014 and December 31, 2013 of $112 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, 2014 and December 31, 2013, respectively, and are included in current and long-term debt on the condensed balance sheets.   Appalachian Consumer Rate Relief Funding has securitized assets of $365 million and $369 as of March 31, 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 WV 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.

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 

 
(a)
Includes an intercompany item eliminated in consolidation as of March 31, 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, 2014 and 2013 were $2 million and $18 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 Sheet
Exposure
the Balance Sheet
 
Exposure
 
 
(in thousands)
Capital Contribution from SWEPCo
 
$
 7,643 
 
$
 7,643 
 
$
 7,643 
 
$
 7,643 
Retained Earnings
 
 
 1,910 
 
 
 1,910 
 
 
 1,600 
 
 
 1,600 
SWEPCo's Guarantee of Debt
 
 
 - 
 
 
 85,190 
 
 
 - 
 
 
 61,348 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Investment in DHLC
 
$
 9,553 
 
$
 94,743 
 
$
 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 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,
Company
 
2014 
 
2013 
 
 
(in thousands)
APCo
 
$
 50,136 
 
$
 39,040 
I&M
 
 
 31,969 
 
 
 27,498 
OPCo
 
 
 39,049 
 
 
 54,069 
PSO
 
 
 24,439 
 
 
 18,161 
SWEPCo
 
 
 33,023 
 
 
 27,480 

 
184
 
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
Company
 
Balance Sheet
 
Exposure
 
Balance Sheet
 
Exposure
 
 
(in thousands)
APCo
 
$
 19,304 
 
$
 19,304 
 
$
 20,191 
 
$
 20,191 
I&M
 
 
 12,040 
 
 
 12,040 
 
 
 12,864 
 
 
 12,864 
OPCo
 
 
 14,046 
 
 
 14,046 
 
 
 31,425 
 
 
 31,425 
PSO
 
 
 9,330 
 
 
 9,330 
 
 
 10,596 
 
 
 10,596 
SWEPCo
 
 
 12,833 
 
 
 12,833 
 
 
 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,
Company
 
2014 
 
2013 
 
 
(in thousands)
I&M
 
$
 70,422 
 
$
 58,535 
OPCo
 
 
- 
 
 
 38,711 

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
Company
 
the Balance Sheet
 
Exposure
 
the Balance Sheet
 
Exposure
 
 
(in thousands)
I&M
 
$
 24,364 
 
$
 24,364 
 
$
 23,916 
 
$
 23,916 
OPCo
 
 
- 
 
 
- 
 
 
 12,810 
 
 
 12,810 

 
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 in 2014 were up 40% in AEP’s western region and 24% in AEP’s eastern region.  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.

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 quarter 2014 industrial sales volumes increased 2.2% over the first quarter 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.

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.

 
186
 
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, 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
Company
 
Low
 
High
 
 
(in millions) 
APCo
 
$
 310 
 
$
 360 
I&M
 
 
 410 
 
 
 470 
PSO
 
 
 280 
 
 
 320 
SWEPCo
 
 
 910 
 
 
 1,060 

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 or federal implementation plans 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 intent to retire the following plants or units of plants before or during 2016:

 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs) 
APCo
 
Clinch River Plant, Unit 3
 
 
 235 
APCo
 
Glen Lyn Plant
 
 
 335 
APCo
 
Kanawha River Plant
 
 
 400 
APCo/AGR
 
Sporn Plant, Units 1-4
 
 
 600 
I&M
 
Tanners Creek Plant, Units 1-4
 
 
 995 
PSO
 
Northeastern Station, Unit 4
 
 
 470 
SWEPCo
 
Welsh Plant, Unit 2
 
 
 528 

As of March 31, 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 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 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.

 
187
 
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.  Nearly all of the states in which the Registrant Subsidiaries’ power plants are located are covered by CAIR.

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) 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.

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, and is currently reviewing the NAAQS for ozone.  States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for facilities as a result of those evaluations.  Management cannot currently predict the nature, stringency or timing of those requirements.

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

Cross-State Air Pollution Rule (CSAPR)

In 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
 
 
188
 
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.  Separate appeals of the supplemental rule, the Error Corrections Rule and the further revisions have been filed, but are being held in abeyance.

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

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  The effective date of the final rule was April 16, 2012 and compliance is required within three years.  The AEP System is participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed.  In 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.

The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and allows operators to exclude periods of startup and shutdown from the emissions averaging periods.  The compliance time frame remains a serious concern.  A one-year administrative extension may be available if the extension is necessary for the installation of controls or to avoid a serious reliability problem.  In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades.  Management is concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines.  The AEP System participated in petitions for review filed in the U.S. Court of Appeals for 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 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.

 
189
 
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.”  Management cannot currently predict the impact these programs may have on future resource plans or the existing generating fleet, but the costs may be substantial.

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

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

Coal Combustion Residual Rule

In 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units 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.  In January 2014, the parties filed a motion with the court to establish December 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.

 
190
 
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 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 a final rule is expected in 2014.  Management is preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

In addition, the Federal EPA issued an information collection request and is developing revised effluent limitation guidelines for electricity generating facilities.  A proposed rule was signed in April 2013 with a final rule expected in 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.

In March 2014, the Federal EPA and the U.S. Army Corps of Engineers jointly announced that they will be issuing 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 of the proposed rule.  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.

 
191
 
Climate Change

National public policy makers and regulators in the 10 states the Registrant Subsidiaries serve have diverse views on climate change.  Management is currently focused on responding to these emerging views with prudent actions, such as improving energy efficiency, investing in developing cost-effective and less carbon-intensive technologies and evaluating assets across a range of plausible scenarios and outcomes.  Management is also 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 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.

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 first 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
 
 
192
 
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, 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 settlement in the SPP integrated market.  Apart from this, there have been no material changes (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter of 2014 that have materially affected, or are 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 5 incorporated herein by reference.

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, OPCo filed its 2012 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.

 
193
 
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 generation and distribution base rate biennial review 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.
 
Ohio may require a reduction in our 2012 and 2013 fuel deferrals. – Affecting AEP and OPCo

In April 2014, the PUCO-selected outside consultant provided its preliminary draft report related to their 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013.  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.
 
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.

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.

Item 5.  Other Information

None

Item 6.  Exhibits

12 – Computation of Consolidated Ratio of Earnings to Fixed Charges

31(a) – Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31(b) – Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32(a) – Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
32(b) – Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

95 – Mine Safety Disclosures

101.INS – XBRL Instance Document
101.SCH – XBRL Taxonomy Extension Schema
101.CAL – XBRL Taxonomy Extension Calculation Linkbase
101.DEF – XBRL Taxonomy Extension Definition Linkbase
101.LAB – XBRL Taxonomy Extension Label Linkbase
101.PRE – XBRL Taxonomy Extension Presentation Linkbase

 
194
 

 
 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  
 
 
 
195