q113aep10q.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended March 31, 2013
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____

Commission
 
Registrants; States of Incorporation;
 
I.R.S. Employer
File Number
 
Address and Telephone Number
 
Identification Nos.
         
1-3525
 
AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)
 
13-4922640
1-3457
 
APPALACHIAN POWER COMPANY (A Virginia Corporation)
 
54-0124790
1-3570
 
INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)
 
35-0410455
1-6543
 
OHIO POWER COMPANY (An Ohio Corporation)
 
31-4271000
0-343
 
PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)
 
73-0410895
1-3146
 
SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)
 
72-0323455
   
1 Riverside Plaza, Columbus, Ohio 43215-2373
   
   
Telephone (614) 716-1000
   

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
           
Yes
X
 
No
   

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

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

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

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

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

 
 

 

     
Number of shares of common stock outstanding of the registrants as of
April 25, 2013
       
American Electric Power Company, Inc.
   
486,045,098
     
($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, 2013

   
Page
Number
Glossary of Terms
 
i
     
Forward-Looking Information
 
iv
     
Part I. FINANCIAL INFORMATION
   
       
 
Items 1, 2 and 3 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Quantitative and Qualitative Disclosures About Market Risk:
 
   
American Electric Power Company, Inc. and Subsidiary Companies:
   
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
1
 
Condensed Consolidated Financial Statements
 
26
 
Index of Condensed Notes to Condensed Consolidated Financial Statements
 
32
       
Appalachian Power Company and Subsidiaries:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
73
 
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 Subsidiary:
   
 
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
 
126
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
132
       
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
133
       
Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries
 
187
       
Controls and Procedures
 
193
 
 
 

 
Part II.  OTHER INFORMATION
   
     
 
Item 1.
Legal Proceedings
 
194
 
Item 1A.
Risk Factors
 
194
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
195
 
Item 4.
Mine Safety Disclosures
 
195
 
Item 5.
Other Information
 
195
 
Item 6.
Exhibits:
 
195
         
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
   
196

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., a utility holding company.
AEP Consolidated
 
AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit
 
AEP Credit, Inc., a consolidated variable interest entity of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East Companies
 
APCo, I&M, KPCo and OPCo.
AEP Energy
 
AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.  BlueStar began doing business as AEP Energy, Inc. in June 2012.
AEPGenCo
 
AEP Generation Resources Inc., a nonregulated AEP subsidiary in the Generation and Marketing segment.
AEP System
 
American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP Transmission Holding Company
 
AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEPSC
 
American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo
 
American Electric Power Transmission Company, a wholly-owned subsidiary of AEP Transmission Holding Company.
AFUDC
 
Allowance for Funds Used During Construction.
AOCI
 
Accumulated Other Comprehensive Income.
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
APSC
 
Arkansas Public Service Commission.
BlueStar
 
BlueStar Energy Holdings, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.  BlueStar began doing business as AEP Energy, Inc. in June 2012.
CAA
 
Clean Air Act.
CLECO
 
Central Louisiana Electric Company, a nonaffiliated utility company.
CO2
 
Carbon dioxide and other greenhouse gases.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CRES
 
Competitive Retail Electric Service.
CSPCo
 
Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
CWIP
 
Construction Work in Progress.
DCC Fuel
 
DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC and DCC Fuel V LLC, consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC
 
Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
EIS
 
Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entity of AEP.
ERCOT
 
Electric Reliability Council of Texas regional transmission organization.
ESP
 
Electric Security Plans, filed with the PUCO, pursuant to the Ohio Amendments.
ETT
 
Electric Transmission Texas, LLC, an equity interest joint venture between AEP and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FAC
 
Fuel Adjustment Clause.
 
 
i

 
 
Term
 
Meaning
     
FASB
 
Financial Accounting Standards Board.
Federal EPA
 
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
FGD
 
Flue Gas Desulfurization or scrubbers.
FTR
 
Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP
 
Accounting Principles Generally Accepted in the United States of America.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IEU
 
Industrial Energy Users-Ohio.
IGCC
 
Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement
 
An agreement by and among APCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
IRS
 
Internal Revenue Service.
IURC
 
Indiana Utility Regulatory Commission.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
 
Kentucky Public Service Commission.
KWh
 
Kilowatthour.
LPSC
 
Louisiana Public Service Commission.
MISO
 
Midwest Independent Transmission System Operator.
MMBtu
 
Million British Thermal Units.
MPSC
 
Michigan Public Service Commission.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWh
 
Megawatthour.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
OCC
 
Corporation Commission of the State of Oklahoma.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OPEB
 
Other Postretirement Benefit Plans.
OTC
 
Over the counter.
PJM
 
Pennsylvania – New Jersey – Maryland regional transmission organization.
PM
 
Particulate Matter.
POLR
 
Provider of Last Resort revenues.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants; APCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
 
A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
RTO
 
Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine
 
Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC
 
U.S. Securities and Exchange Commission.
SEET
 
Significantly Excessive Earnings Test.
 
 
ii

 
 
Term
 
Meaning
     
SIA
 
System Integration Agreement, effective June 15, 2000, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF
 
Spent Nuclear Fuel.
SO2
 
Sulfur dioxide.
SPP
 
Southwest Power Pool regional transmission organization.
SSO
 
Standard service offer.
Stall Unit
 
J. Lamar Stall Unit at Arsenal Hill Plant, a 543 MW natural gas unit owned by SWEPCo.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC
 
AEP Texas Central Company, an AEP electric utility subsidiary.
TNC
 
AEP Texas North Company, an AEP electric utility subsidiary.
Transition Funding
 
AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas restructuring law.
Turk Plant
 
John W. Turk, Jr. Plant, a 600 MW coal-fired plant under construction in Arkansas that is 73% owned by SWEPCo.
Utility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE
 
Variable Interest Entity.
Virginia SCC
 
Virginia State Corporation Commission.
WPCo
 
Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC
 
Public Service Commission of West Virginia.
     

 
iii

 

FORWARD-LOOKING INFORMATION

This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2012 Annual Report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

·
The economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory.
·
Inflationary or deflationary interest rate trends.
·
Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·
The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
·
Electric load, customer growth and the impact of retail competition, particularly in Ohio.
·
Weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
·
Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·
Availability of necessary generating capacity and the performance of our generating plants.
·
Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·
Our ability to build or acquire generating capacity and transmission lines and facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.
·
New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants and related assets.
·
Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
·
A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
·
Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
·
Resolution of litigation.
·
Our ability to constrain operation and maintenance costs.
·
Our ability to develop and execute a strategy based on a view regarding prices of electricity, coal, natural gas and other energy-related commodities.
·
Prices and demand for power that we generate and sell at wholesale.
·
Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·
Our ability to recover through rates or market prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.
· Volatility and changes in markets for electricity, coal, natural gas and other energy-related commodities.
 
 
iv

 
 
·
Changes in utility regulation, including the implementation of ESPs and the transition to market and expected legal separation for generation in Ohio and the allocation of costs within regional transmission
  organizations, including PJM and SPP.
·
Our ability to successfully manage negotiations with stakeholders and obtain regulatory approval to terminate the Interconnection Agreement.
·
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·
Actions of rating agencies, including changes in the ratings of our debt.
·
The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact on future funding requirements.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
·
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

The forward looking statements of AEP and its Registrant Subsidiaries speak only as of the date of this report or as of the date they are made.  AEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 2012 Annual Report and in Part II of this report.

 
v

 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Corporate Separation, Plant Transfers and Termination of  Interconnection Agreement

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets at net book value to AEPGenCo.  AEPGenCo will also assume the associated generation liabilities.  In December 2012, the PUCO granted the IEU and the Ohio Consumers’ Counsel requests for rehearing, which were denied by the PUCO in April 2013.

Also in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations.  The filings requested approval to transfer at net book value approximately 9,200 MW of OPCo-owned generation assets to AEPGenCo.  The AEP East Companies also requested FERC approval to transfer at net book value OPCo’s current two-thirds ownership (867 MW) in Amos Plant Unit 3 to APCo and transfer at net book value OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests (780 MW each).  These transfers are proposed to be effective no later than December 31, 2013.  Additionally, the AEP East Companies asked the FERC, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ power supply resources.  Under the PCA, APCo, I&M and KPCo would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies.  Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.  Intervenors have opposed several of these filings.  The AEP East Companies responded to intervenor comments and filed a revised PCA at the FERC in March 2013.  The revised PCA included certain clarifying wording changes that have been agreed upon by intervenors.  A decision from the FERC is expected in the second quarter of 2013.     
 
In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval of the Amos Plant and Mitchell Plant transfers discussed above.  Hearings at the Virginia SCC and the WVPSC are scheduled for June 2013 and July 2013, respectively.  If the transfers are approved, APCo and WPCo anticipate seeking cost recovery in upcoming rate proceedings.  If APCo and WPCo are not ultimately permitted to recover their incurred costs, it could reduce future net income and cash flows and impact financial condition.  See the “Plant Transfers” section of APCo and WPCo Rate Matters section of Note 3.

Also in December 2012, KPCo filed a request with the KPSC for approval of the Mitchell Plant transfer discussed above.  If the transfer is approved, KPCo anticipates seeking cost recovery when filing its next base rate case.  A hearing at the KPSC is scheduled for May 2013.  If KPCo is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows and impact financial condition.  See the “Plant Transfer” section of KPCo Rate Matters section of Note 3.

If approved as filed, results of operations related to generation in Ohio will be largely determined by prevailing market conditions effective January 1, 2014.

Ohio Electric Security Plan Filing

2009 – 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover OPCo’s deferred fuel costs in rates beginning September 2012.  As of March 31, 2013, OPCo’s net deferred fuel balance was $501 million, excluding unrecognized equity carrying costs.  Decisions from the Supreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance.

 
1

 
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.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The RPM price is approximately $20/MW day through May 2013 then $33/MW day through May 2014.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 PUCO ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR is expected to provide approximately $500 million over the ESP period and will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs.  As of March 31, 2013, OPCo’s incurred deferred capacity costs balance of $116 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

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

Ohio Customer Choice

In our Ohio service territory, various CRES providers are targeting retail customers by offering alternative generation service.  The reduction in gross margin as a result of customer switching in Ohio is partially offset by (a) collection of capacity revenues from CRES providers, (b) off-system sales, (c) deferral of unrecovered capacity costs, (d) Retail Stability Rider collections and (e) revenues from AEP Energy.  AEP Energy is our CRES provider and part of our Generation and Marketing segment which targets retail customers, both within and outside of our retail service territory.

Customer Demand

In comparison to 2012, heating degree days in 2013 were up 59% in our western region and 44% in our eastern region.  Our weather-normalized retail sales were down 1.5% compared to 2012.  Our industrial sales declined 6% partially due to Ormet, a large aluminum company that lowered their production in the third quarter of 2012 by one-third and is currently in bankruptcy proceedings.

In 2013, we anticipate slight increases in retail sales across our service territories primarily driven by oil and gas related projects, including shale gas.  We also anticipate decreases in industrial demand in our eastern region related to Ormet’s lower production levels discussed above.

Significantly Excessive Earnings Test

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

 
2

 
Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.  As of March 31, 2013, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital cost cap, SWEPCo has capitalized approximately $1.7 billion of expenditures, including AFUDC and capitalized interest of $328 million and related transmission costs of $120 million.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%).  Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN.  In June 2010, in response to the Arkansas Supreme Court’s decision, the APSC issued an order which reversed and set aside the previously granted CECPN.  This portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the SPP market.  If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.  See “Turk Plant” section of Note 3.

Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million, primarily due to the Turk Plant, based upon an 11.25% return on common equity to be effective January 2013.  The requested base rate increase included a return on and of the Texas jurisdictional share (approximately 33%) of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs.  In September 2012, an Administrative Law Judge issued an order that granted the establishment of SWEPCo’s existing rates as temporary rates beginning in late January 2013, subject to true-up to the final PUCT-approved rates.  In December 2012, several intervenors filed opposing testimony with various recommendations.  A decision from the PUCT is expected in the second quarter of 2013.  If the PUCT does not approve full cost recovery of SWEPCo’s assets, it could reduce future net income and cash flows and impact financial condition.  See “2012 Texas Base Rate Case” section of Note 3.

Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant.  In February 2013, a settlement was filed and approved by the LPSC.  The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually.  The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund based on the staff review of the cost of service and the prudence of the Turk Plant to be initiated by SWEPCo no later than May 2013.  The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover all non-fuel Turk Plant costs and a full weighted-average cost of capital return on the Turk Plant portion of rate base, effective January 2013.  If the LPSC orders refunds based upon the staff review of the cost of service or prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

2011 Indiana Base Rate Case

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

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs effective February 2014 over a one year period.  APCo has deferred $28 million as of March 31, 2013 for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $11 million of unrecognized equity carrying costs.  If the Virginia SCC were to disallow any portion of the environmental RAC, it could reduce future net income and cash flows.  See “Environmental Rate Adjustment Clause (Environmental RAC)” section of Note 3.

Generation Rate Adjustment Clause (Generation RAC)

In March 2013, APCo filed with the Virginia SCC for an increase in its generation RAC revenues of $12 million for a total of $38 million annually to collect costs related to the Dresden Plant.  The generation RAC increase is expected to be effective in March 2014.  APCo has deferred $4 million as of March 31, 2013 for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $3 million of unrecognized equity carrying costs.  If the Virginia SCC were to disallow any portion of the generation RAC, it could reduce future net income and cash flows.

Cook Plant Life Cycle Management Project

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life.  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of March 31, 2013, I&M has incurred $197 million related to the LCM Project, including AFUDC.

In April 2012, I&M filed a petition with the IURC for recovery of project costs, including interest, through a new rider.  Several intervenors filed testimony in Indiana with various recommendations including caps on expenditures.  The IURC held a hearing in January 2013 and an order is pending.  In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project.  In April 2013, an intervenor filed an appeal 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” section of Note 3.

LITIGATION

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  We assess the probability of loss for each contingency and accrue a liability for cases that have a probable likelihood of loss if the loss can be estimated.  For details on our regulatory proceedings and pending litigation see Note 3 – Rate Matters, Note 5 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report.  Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies included herein.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with environmental control requirements.  We will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, new 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
 
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discussed below and reductions of CO2 emissions to address concerns about global climate change.  We believe that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report.  We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.   Recovery in Ohio will be dependent upon prevailing market conditions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If we are unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of March 31, 2013, the AEP System had a total generating capacity of 37,600 MWs, of which 23,700 MWs are coal-fired.  We continue to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on our coal-fired generating facilities.  Based upon our estimates, investments to meet these proposed requirements range from approximately $4 billion to $5 billion through 2020.  These amounts include investments to convert 1,570 MWs of coal generation to natural gas capacity.  If natural gas conversion is not completed, the units could be retired sooner than planned.

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

Subject to the factors listed above and based upon our continuing evaluation, we have given notice to the applicable RTOs of our 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/OPCo
 
Philip Sporn Plant, Units 1-4
   
 600 
I&M
 
Tanners Creek Plant, Units 1-3
   
 495 
KPCo
 
Big Sandy Plant, Unit 1
   
 278 
OPCo
 
Kammer Plant
   
 630 
OPCo
 
Muskingum River Plant, Units 1-4
   
 840 
OPCo
 
Picway Plant
   
 100 
SWEPCo
 
Welsh Plant, Unit 2
   
 528 
Total
       
 4,441 

Duke Energy Corporation, the operator of W. C. Beckjord Generating Station, has announced its intent to close the facility in 2015.  OPCo owns 12.5% (53 MWs) of one unit at that station.  In December 2012, we retired OPCo’s 165 MW Conesville Plant, Unit 3.

A decline in natural gas prices, pending environmental rules and the proposed termination of the Interconnection Agreement had an adverse impact on the recoverability of the net book values of certain coal-fired units.  In 2012, we recorded a $287 million pretax impairment charge for OPCo’s net book value of certain plants totaling 1,870 MWs in the table above and the Beckjord and Conesville plants discussed above.  As of March 31, 2013, the net book value of the impaired plants is zero.
 
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As of March 31, 2013, the net book value of the regulated plants in the table above was $449 million.  This amount does not include related inventory or CWIP balances.

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.  We are also evaluating closure of certain units based on changes in emission requirements and demand for power.  The following table lists the plants or units that are either awaiting regulatory approval or are still being evaluated by management:

       
Generating
Company
 
Plant Name and Unit
 
Capacity
       
(in MWs)
APCo
 
Clinch River Plant, Units 1-2
   
 470 
I&M/AEGCo/KPCo
 
Rockport Plant, Units 1-2
   
 2,620 
I&M
 
Tanners Creek Plant, Unit 4
   
 500 
KPCo
 
Big Sandy Plant, Unit 2
   
 800 
OPCo
 
Muskingum River Plant, Unit 5
   
 600 
PSO
 
Northeastern Station, Units 3-4
   
 930 
SWEPCo
 
Flint Creek Plant
   
 264 
Total
       
 6,184 

In December 2012, KPCo announced its plan to retire Big Sandy Plant, Unit 2 in early 2015, subject to regulatory approval, and its intention to study the conversion of Big Sandy Plant, Unit 1 to natural gas.

As of March 31, 2013, the net book values of the regulated plants and nonregulated plant (Muskingum River) in the table above were $1.3 billion and $168 million, respectively.  These amounts do not include related inventory or CWIP balances.

The rules and regulatory actions that may impact the evaluation of specific units are discussed in the following sections.  Clinch River and Tanners Creek units are being considered for gas conversion.  Muskingum River Plant, Unit 5 will have options to cease burning coal and retire in 2015 or cease burning coal in 2015 and complete a refueling project no later than June 2017.  Big Sandy Plant, Unit 2 will have options to retrofit, retire, repower or refuel by 2015.  Natural gas prices and pending environmental rules could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of certain coal-fired units.  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.

Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both of its units at the Rockport Plant with a Dry Sorbent Injection system.  The estimated cost of the CCT Project is $285 million, excluding AFUDC.  The application requested deferral treatment of any unrecovered carrying costs incurred during construction and incremental post in-service depreciation expense and operation and maintenance expenses until such costs are recognized and recovered in a rider.  If I&M receives approval of a CPCN, I&M will file for cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism.  As of March 31, 2013, we have incurred $61 million related to the CCT Project, including AFUDC.  If we are not ultimately permitted to recover our incurred costs, it could reduce future net income and cash flows.

Flint Creek Plant Environmental Controls

In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA.  The estimated cost of the project is $408 million, excluding AFUDC and company overheads.  As a joint owner of the Flint Creek Plant, SWEPCo’s portion of those costs is estimated at $204 million.  As of March 31, 2013, SWEPCo has incurred $16 million related to this project, including AFUDC and company overheads.  In March 2013, the APSC staff and the Arkansas Attorney General Office filed testimony that supported SWEPCo’s petition.  The Sierra Club continues to
 
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oppose SWEPCo’s petition.  Additional hearings were held in March 2013.  If SWEPCo is not ultimately permitted to fully recover the net book value of the Flint Creek Plant and its incurred environmental costs in a future base rate proceeding, it could reduce future net income and cash flows and impact financial condition.

Oklahoma Environmental Compliance Plan

In September 2012, based upon an agreement with the Federal EPA, the State of Oklahoma and other parties, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES) Unit 4 in 2016 and additional environmental controls on NES Unit 3 to continue operations through 2026.  The plan requested approval for (a) an estimated $210 million of new environmental investment, excluding AFUDC and overheads of $46 million, that will be incurred prior to 2016 at NES Unit 3, (b) accelerated recovery through 2026 of the net book value of NES Units 3 and 4 (combined net book value of the two units is $232 million as of March 31, 2013), (c) an estimated $83 million of new investment incurred through 2016 at various gas units and (d) a new 15-year purchase power agreement (PPA) with a nonaffiliated entity, effective in 2016, with cost recovery through a rider, including an annual earnings component of $3 million.  Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery when filing its next base rate case, which is expected to occur no later than 2014.

In January 2013, several parties filed testimony with various recommendations.  In February 2013, the OCC staff requested a stay in this proceeding, which was granted by the OCC in March 2013.  The stay will be in effect until the State Implementation Plan is approved by the Federal EPA, which could be as late as February 2014.  If PSO is ultimately not permitted to fully recover its net book value of NES Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition.  See “Oklahoma Environmental Compliance Plan” section of Note 3.

Clean Air Act Requirements

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

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

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

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

 
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Cross-State Air Pollution Rule (CSAPR)

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

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

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

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

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

The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and allows operators to exclude periods of startup and shutdown from the emissions averaging periods.  The compliance time frame remains a serious concern.  A one-year administrative extension may be available if the extension is necessary for the installation of controls or to avoid a serious reliability problem.  In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades.  We are concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines.  We are participating in petitions for review filed in the U.S. Court of Appeals for the District of Columbia Circuit by several organizations of which we are members.  Certain issues related to the standards for new coal-fired units have been severed from the main case and are being held in abeyance pending completion of the Federal EPA’s reconsideration proceeding.  The case is proceeding on the remaining issues and briefing was completed in April 2013.

 
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Regional Haze

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

CO2 Regulation

In March 2012, the Federal EPA issued a proposal to regulate CO2 emissions from new fossil fuel-fired electricity generating units.  The proposed rule establishes a new source performance standard of 1,000 pounds of CO2 per megawatt hour of electricity generated, a rate that most natural gas combined cycle units can meet, but that is substantially below the emission rate of a new pulverized coal generator or an integrated gas combined cycle unit that uses coal for fuel.  As proposed, the rule does not apply to new gas-fired stationary combustion turbines used as peaking units, does not apply to existing, modified or reconstructed sources, and does not apply to units whose CO2 emission rate increases as a result of the addition of pollution control equipment to control criteria pollutant emissions or HAPs.  The rule is not anticipated to have a significant immediate impact on the AEP System since it does not apply to existing units or units that have already commenced construction.  New source performance standards affect units that have not yet received permits.  The proposed standards were challenged in the U.S. Court of Appeals for the District of Columbia Circuit.  That case was dismissed because the court determined that no final agency action had yet been taken.  The Federal EPA is expected to finalize these standards in 2013.

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

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

Coal Combustion Residual Rule

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

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

Clean Water Act Regulations

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

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

Climate Change

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

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

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

Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others.  We have been named in pending lawsuits, which we are defending.  It is not possible to predict the outcome of these lawsuits or their impact on our operations or financial condition.  See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 4.

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

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

RESULTS OF OPERATIONS

SEGMENTS

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

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

Utility Operations

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

Transmission Operations

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

AEP River Operations

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

Generation and Marketing

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

 
11

 
The table below presents Net Income by segment for the three months ended March 31, 2013 and 2012.

   
Three Months Ended March 31,
   
2013 
 
2012 
   
(in millions)
Utility Operations
$
 349 
 
$
 384 
Transmission Operations
 
 13 
   
 9 
AEP River Operations
 
 (2)
   
 9 
Generation and Marketing
 
 7 
   
 (1)
All Other (a)
 
 (3)
   
 (11)
Net Income
$
 364 
 
$
 390 

(a)
While not considered a reportable segment, All Other includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

AEP CONSOLIDATED

First Quarter of 2013 Compared to First Quarter of 2012

Net Income decreased from $390 million in 2012 to $364 million in 2013 primarily due to:

·
The loss of retail customers in Ohio to various CRES providers.
·
A first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of the Ohio modified stipulation.
·
A write-off in the first quarter of 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.
·
Higher costs associated with plant outages in 2013.
·
A decrease in AEP River Operations' 2013 earnings due to the impact of the 2012 drought.

These decreases were partially offset by:

·
Successful rate proceedings in our various jurisdictions.
·
An increase in weather-related usage.
·
A decrease in Ohio depreciation expense due to the following:
 
·
The November 2012 impairment for certain Ohio generation plants.
 
·
The deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.

Average basic shares outstanding increased from 484 million in 2012 to 486 million in 2013.  Actual shares outstanding were 486 million as of March 31, 2013.

Our results of operations are discussed below by operating segment.

 
12

 
UTILITY OPERATIONS

We believe that a discussion of the results from our Utility Operations segment on a gross margin basis is most appropriate in order to further understand the key drivers of the segment.  Gross Margin represents total revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances and purchased electricity.

   
Three Months Ended
   
March 31,
   
2013 
 
2012 
   
(in millions)
Revenues
$
 3,517 
 
$
 3,385 
Fuel and Purchased Electricity
 
 1,277 
   
 1,269 
Gross Margin
 
 2,240 
   
 2,116 
Other Operation and Maintenance
 
 879 
   
 755 
Depreciation and Amortization
 
 406 
   
 412 
Taxes Other Than Income Taxes
 
 209 
   
 211 
Operating Income
 
 746 
   
 738 
Interest and Investment Income
 
 3 
   
 1 
Carrying Costs Income
 
 4 
   
 20 
Allowance for Equity Funds Used During Construction
 
 10 
   
 20 
Interest Expense
 
 (226)
   
 (217)
Income Before Income Tax Expense and Equity Earnings
 
 537 
   
 562 
Income Tax Expense
 
 188 
   
 179 
Equity Earnings of Unconsolidated Subsidiaries
 
 - 
   
 1 
Net Income
$
 349 
 
$
 384 

Summary of KWh Energy Sales for Utility Operations
 
   
Three Months Ended March 31,
 
2013 
 
2012 
   
(in millions of KWhs)
Retail:
         
 
Residential
 
 16,255 
   
 14,799 
 
Commercial
 
 11,551 
   
 11,265 
 
Industrial
 
 13,761 
   
 14,647 
 
Miscellaneous
 
 709 
   
 721 
Total Retail (a)
 
 42,276 
   
 41,432 
           
Wholesale
 
 11,024 
   
 8,913 
           
Total KWhs
 
 53,300 
   
 50,345 
             
(a)  Represents energy delivered to distribution customers.

 
13

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

Summary of Heating and Cooling Degree Days for Utility Operations
 
   
Three Months Ended March 31,
   
2013 
 
2012 
   
(in degree days)
           
Eastern Region
         
Actual - Heating (a)
 
 1,818 
   
 1,261 
Normal - Heating (b)
 
 1,719 
   
 1,751 
             
Actual - Cooling (c)
 
 - 
   
 28 
Normal - Cooling (b)
 
 4 
   
 3 
             
Western Region
         
Actual - Heating (a)
 
 552 
   
 347 
Normal - Heating (b)
 
 569 
   
 581 
             
Actual - Cooling (d)
 
 70 
   
 133 
Normal - Cooling (b)
 
 62 
   
 60 
             
(a)
Eastern Region and Western Region heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.
(d)
Western Region cooling degree days are calculated on a 65 degree temperature base for PSO/SWEPCo and a 70 degree temperature base for TCC/TNC.

 
14

 


First Quarter of 2013 Compared to First Quarter of 2012
 
               
Reconciliation of First Quarter of 2012 to First Quarter of 2013
Net Income from Utility Operations
(in millions)
               
First Quarter of 2012
       
$
 384 
               
Changes in Gross Margin:
           
Retail Margins
         
 117 
Off-system Sales
         
 (30)
Transmission Revenues
         
 21 
Other Revenues
         
 16 
Total Change in Gross Margin
         
 124 
             
Changes in Expenses and Other:
           
Other Operation and Maintenance
         
 (124)
Depreciation and Amortization
         
 6 
Taxes Other Than Income Taxes
         
 2 
Interest and Investment Income
         
 2 
Carrying Costs Income
         
 (16)
Allowance for Equity Funds Used During Construction
         
 (10)
Interest Expense
         
 (9)
Equity Earnings of Unconsolidated Subsidiaries
         
 (1)
Total Change in Expenses and Other
         
 (150)
               
Income Tax Expense
         
 (9)
               
First Quarter of 2013
       
$
 349 

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 $117 million primarily due to the following:
 
·
A $78 million increase in weather-related usage primarily due to 44% and 59% increases in heating degree days in our eastern and western service territories, respectively.
 
·
Successful rate proceedings in our service territories which include:
   
·
A $61 million rate increase for OPCo.
   
·
A $28 million rate increase for APCo.
   
·
A $23 million rate increase for SWEPCo.
       
For the rate increases described above, $58 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
 
These increases were partially offset by:
 
·
An $87 million decrease attributable to Ohio customers switching to alternative CRES providers.  This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
·
Margins from Off-system Sales decreased $30 million primarily due to lower Ohio CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity payments and reduced trading and marketing margins, partially offset by higher physical sales volumes and margins.  The decrease in Ohio CRES capacity revenues is partially offset in other expense items below.
·
Transmission Revenues increased $21 million primarily due to increased transmission revenues from Ohio customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers offsets a portion of the lost revenues included in Retail Margins above.
·
Other Revenues increased $16 million primarily due to an increase in revenues related to recovery of equity carrying costs income on TCC's issuance of securitization bonds in March 2012.  This increase is partially offset by an increase in Depreciation and Amortization expense.

 
15

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

·
Other Operation and Maintenance expenses increased $124 million primarily due to the following:
 
·
A $35 million increase due to the first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of the Ohio modified stipulation.
 
·
A $30 million write-off in the first quarter of 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.
 
·
A $26 million increase in remitted Universal Service Fund (USF) surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase was offset by a corresponding increase in Retail Margins.
 
·
An $18 million increase in energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
 
·
A $16 million increase in plant outage and other plant operating and maintenance expenses.
 
·
A $9 million increase in transmission services due to increased RTO expense within SPP.
 
·
A $7 million increase due to expenses related to the completion of the 2012 sustainable cost reductions program in the first quarter of 2013.
 
·
A $5 million increase in distribution maintenance expense primarily due to the January 2013 snow storm in our eastern region.
 
These increases were partially offset by:
 
·
A $25 million decrease due to an agreement reached to settle an insurance claim.
·
Depreciation and Amortization expenses decreased $6 million primarily due to the following:
 
·
A $27 million decrease as a result of depreciation ceasing on certain Ohio generating plants that were impaired in November 2012.
 
·
A $20 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
 
These decreases were partially offset by:
 
·
An $11 million increase due to the Turk Plant being placed in service in December 2012.
 
·
A $6 million combined increase in depreciation for APCo and I&M primarily due to increases in depreciation rates effective February 2012 (Virginia), April 2012 (Michigan) and March 2013 (Indiana), respectively.  The majority of this increase in depreciation is offset within Gross Margin.
 
·
A $5 million increase due to TCC’s issuance of securitization bonds in March 2012.  The increase in TCC’s securitization related amortizations are offset within Gross Margin.
 
·
A $3 million increase as a result of Dresden Plant being placed in service in late January 2012.
 
·
Overall higher depreciable property balances.
·
Carrying Costs Income decreased $16 million primarily due to the following:
 
·
An $8 million decrease in carrying costs income due to the first quarter 2012 recording of debt carrying costs prior to TCC's issuance of securitization bonds in March 2012.
 
·
An $8 million decrease due to an increased recovery of Virginia environmental costs in new base rates as approved by the Virginia SCC in late January 2012 and decreased carrying charges related to Dresden Plant.
·
Allowance for Equity Funds Used During Construction decreased $10 million primarily due to completed construction of the Turk Plant in December 2012.
·
Interest Expense increased $9 million primarily due to a decrease in the debt component of AFUDC due to completed construction of the Turk Plant in December 2012, partially offset by lower long-term interest rates.
·
Income Tax Expense increased $9 million primarily due to favorable audit settlements for previous years recorded in 2012, partially offset by a decrease in pretax book income.

 
16

 
TRANSMISSION OPERATIONS

First Quarter of 2013 Compared to First Quarter of 2012

Net Income from our Transmission Operations segment increased from $9 million in 2012 to $13 million in 2013 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT.

AEP RIVER OPERATIONS

First Quarter of 2013 Compared to First Quarter of 2012

Net Income from our AEP River Operations segment decreased from income of $9 million in 2012 to a loss of $2 million in 2013 primarily due to the 2012 drought, which continued to have negative impacts on river conditions and 2012 crop yields, resulting in reduced grain exports.

GENERATION AND MARKETING

First Quarter of 2013 Compared to First Quarter of 2012

Net Income from our Generation and Marketing segment increased from a loss of $1 million in 2012 to income of $7 million in 2013 primarily due to increased retail activity resulting from our 2012 acquisition of BlueStar and higher trading and marketing margins, partially offset by lower wind production.

ALL OTHER

First Quarter of 2013 Compared to First Quarter of 2012

Net Income from All Other increased from a loss of $11 million in 2012 to a loss of $3 million in 2013 primarily due to a reduction in interest expense from lower long-term interest rates.

AEP SYSTEM INCOME TAXES

First Quarter of 2013 Compared to First Quarter of 2012

Income Tax Expense increased $6 million primarily due to audit settlements for previous years recorded in 2012, partially offset by a decrease 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, 2013
 
December 31, 2012
   
(dollars in millions)
Long-term Debt, including amounts due within one year
$
 17,573 
 
 51.2 
%
 
$
 17,757 
 
 52.3 
%
Short-term Debt
 
 1,307 
 
 3.8 
     
 981 
 
 2.9 
 
Total Debt
 
 18,880 
 
 55.0 
     
 18,738 
 
 55.2 
 
AEP Common Equity
 
 15,421 
 
 45.0 
     
 15,237 
 
 44.8 
 
                       
Total Debt and Equity Capitalization
$
 34,301 
 
 100.0 
%
 
$
 33,975 
 
 100.0 
%

 
17

 
Our ratio of debt-to-total capital decreased from 55.2% as of December 31, 2012 to 55% as of March 31, 2013.  Short-term debt outstanding increased primarily due to borrowing for our commercial paper program under credit facilities and our common equity increased due to earnings.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability.  We believe we have adequate liquidity under our existing credit facilities.  As of March 31, 2013, we had $4.5 billion in aggregate credit facility commitments to support our operations.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  We are committed to maintaining adequate liquidity.  We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, sale-and-leaseback or leasing agreements or common stock.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  As of March 31, 2013, our available liquidity was approximately $3.7 billion as illustrated in the table below:

     
Amount
   
Maturity
     
(in millions)
     
Commercial Paper Backup:
           
 
Revolving Credit Facility
 
$
 1,750 
   
June 2016
 
Revolving Credit Facility
   
 1,750 
   
July 2017
Term Credit Facility
   
 1,000 
   
May 2015
Total
   
 4,500 
     
Cash and Cash Equivalents
   
 179 
     
Total Liquidity Sources
   
 4,679 
     
Less:
AEP Commercial Paper Outstanding
   
 661 
     
 
Letters of Credit Issued
   
 115 
     
 
Draw on Term Credit Facility
   
 200 
     
               
Net Available Liquidity
 
$
 3,703 
     

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 2013 was $836 million.  The weighted-average interest rate for our commercial paper during 2013 was 0.35%.

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

Securitized Accounts Receivable

In 2012, we renewed our receivables securitization agreement.  The agreement provides a commitment of $700 million from bank conduits to purchase receivables.  A commitment of $385 million expires in June 2013 and the remaining commitment of $315 million expires in June 2015.  We intend to extend or replace the agreement expiring in June 2013 on or before its maturity.

 
18

 
West Virginia Securitization of Regulatory Assets

In March 2012, West Virginia passed securitization legislation which allows the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred Expanded Net Energy Charge (ENEC) balances and other ENEC related assets.  In August 2012, APCo and WPCo filed with the WVPSC a request for a financing order to securitize $422 million related to APCo’s December 2011 under-recovered ENEC deferral balance, other ENEC-related assets and related financing costs.  In March 2013, APCo, WPCo and intervenors filed a settlement agreement with the WVPSC, which recommended the WVPSC authorize APCo to securitize $376 million plus upfront financing costs.  A decision is pending from the WVPSC.

Ohio Securitization of Regulatory Assets

In March 2013, the PUCO approved OPCo’s request to securitize the Deferred Asset Recovery Rider (DARR) balance.  As of March 31, 2013, OPCo’s DARR balance was $277 million, including $130 million of unrecognized equity carrying costs.  The DARR is being recovered through 2018 by a non-bypassable rider.  Once the securitization bonds are issued, the DARR will cease and will be replaced by the Deferred Asset Phase-in Rider, which will recover the securitized asset over a period not to exceed eight years.  The securitization bonds are expected to be issued in mid-2013.

Debt Covenants and Borrowing Limitations

Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually defined in our revolving credit agreements.  Debt as defined in the revolving credit agreements excludes securitization bonds and debt of AEP Credit.  As of March 31, 2013, this contractually-defined percentage was 51.4%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  As of March 31, 2013, we complied with all of the covenants contained in these credit agreements.  In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements and in a majority of our non-exchange traded commodity contracts which would permit the lenders and counterparties to declare the outstanding amounts payable.  However, a default under our non-exchange traded commodity contracts does not cause an event of default under our revolving credit agreements.

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

The term credit facility may be drawn upon until February 2014.  Repayments prior to maturity are permitted.  However, any amount that is repaid may not be re-borrowed and is a permanent reduction to the facility.
 
Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  As of March 31, 2013, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.49 per share in April 2013.  Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time.  Our income derives from our common stock equity in the earnings of our utility subsidiaries.  Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

We do not believe restrictions related to our various financing arrangements and regulatory requirements will have any significant impact on Parent’s ability to access cash to meet the payment of dividends on its common stock.

 
19

 
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,
     
2013 
 
2012 
     
(in millions)
Cash and Cash Equivalents at Beginning of Period
 
$
 279 
 
$
 221 
Net Cash Flows from Operating Activities
   
 756 
   
 876 
Net Cash Flows Used for Investing Activities
   
 (772)
   
 (792)
Net Cash Flows Used for Financing Activities
   
 (84)
   
 (19)
Net Increase (Decrease) in Cash and Cash Equivalents
   
 (100)
   
 65 
Cash and Cash Equivalents at End of Period
 
$
 179 
 
$
 286 

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,
     
2013 
 
2012 
     
(in millions)
Net Income
 
$
 364 
 
$
 390 
Depreciation and Amortization
   
 420 
   
 423 
Other
   
 (28)
   
 63 
Net Cash Flows from Operating Activities
 
$
 756 
 
$
 876 

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.

Net Cash Flows from Operating Activities were $876 million in 2012 consisting primarily of Net Income of $390 million and $423 million of noncash Depreciation and Amortization.  Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  A significant change in other items includes the favorable impact of a decrease in accounts receivable and the unfavorable impact of an increase in fuel inventory due to the mild weather.  Deferred Income Taxes increased primarily due to provisions in the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Jobs Creation Act and an increase in tax versus book temporary differences from operations.

 
20

 
Investing Activities
           
 
               
     
Three Months Ended
     
March 31,
     
2013 
 
2012 
     
(in millions)
Construction Expenditures
 
$
 (843)
 
$
 (741)
Acquisitions of Nuclear Fuel
   
 (47)
   
 (11)
Acquisitions of Assets/Businesses
   
 (2)
   
 (85)
Insurance Proceeds Related to Cook Plant Fire
   
 72 
   
 - 
Proceeds from Sales of Assets
   
 1 
   
 8 
Other
   
 47 
   
 37 
Net Cash Flows Used for Investing Activities
 
$
 (772)
 
$
 (792)

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

Net Cash Flows Used for Investing Activities were $792 million in 2012 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments.  Acquisitions of Assets/Businesses include our March 2012 purchase of BlueStar for $70 million.
 
 
Financing Activities
           
 
               
     
Three Months Ended
     
March 31,
     
2013 
 
2012 
     
(in millions)
Issuance of Common Stock, Net
 
$
 15 
 
$
 31 
Issuance of Debt, Net
   
 139 
   
 193 
Dividends Paid on Common Stock
   
 (230)
   
 (229)
Other
   
 (8)
   
 (14)
Net Cash Flows Used for Financing Activities
 
$
 (84)
 
$
 (19)

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.  See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows Used for Financing Activities in 2012 were $19 million.  Our net debt issuances were $193 million. The net issuances included issuances of $800 million securitization bonds, $275 million of senior unsecured notes and $67 million of notes payable offset by retirements of $191 million of senior unsecured and other debt notes, $50 million of pollution control bonds, $98 million of securitization bonds and a decrease in short-term borrowing of $600 million.  We paid common stock dividends of $229 million.

In April 2013, I&M retired $28 million of Notes Payable related to DCC Fuel.

In April 2013, I&M reacquired $40 million of 5.25% Pollution Control Bonds due in 2025.  The variable rate bonds are held by a trustee on behalf of I&M.

 
21

 
OFF-BALANCE SHEET ARRANGEMENTS

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

     
March 31,
 
December 31,
     
2013 
 
2012 
     
(in millions)
Rockport Plant Unit 2 Future Minimum Lease Payments
 
$
 1,478 
 
$
 1,478 
Railcars Maximum Potential Loss From Lease Agreement
   
 25 
   
 25 

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

CONTRACTUAL OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2012 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

ACCOUNTING PRONOUNCEMENTS

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes.  The FASB is currently working on several projects including revenue recognition, financial instruments, leases, insurance, hedge accounting and consolidation policy.  The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

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

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

 
22

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

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

 
MTM Risk Management Contract Net Assets (Liabilities)
 
Three Months Ended March 31, 2013
   
       
Generation
   
   
Utility
and
 
   
Operations
Marketing
Total
   
(in millions)
Total MTM Risk Management Contract Net Assets
               
 
as of December 31, 2012
$
 68 
 
$
 128 
 
$
 196 
(Gain) Loss from Contracts Realized/Settled During the Period and
               
 
Entered in a Prior Period
 
 (12)
   
 (10)
   
 (22)
Fair Value of New Contracts at Inception When Entered During the
               
 
Period (a)
 
 - 
   
 3 
   
 3 
Changes in Fair Value Due to Market Fluctuations During the
               
 
Period (b)
 
 - 
   
 8 
   
 8 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
 
 6 
   
 - 
   
 6 
Total MTM Risk Management Contract Net Assets
               
 
as of March 31, 2013
$
 62 
 
$
 129 
   
 191 
                   
Commodity Cash Flow Hedge Contracts
             
 20 
Interest Rate and Foreign Currency Cash Flow Hedge Contracts
             
 (2)
Collateral Deposits
             
 15 
Total MTM Derivative Contract Net Assets as of March 31, 2013
           
$
 224 

(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.
 
23

 
Credit Risk

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

We have risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily.  As of March 31, 2013, our credit exposure net of collateral to sub investment grade counterparties was approximately 6.6%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).  As of March 31, 2013, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

     
Exposure
         
Number of
 
Net Exposure
   
Before
   
Counterparties
of
   
Credit
Credit
Net
>10% of
Counterparties
Counterparty Credit Quality
Collateral
Collateral
Exposure
Net Exposure
>10%
     
(in millions, except number of counterparties)
Investment Grade
 
$
 592 
 
$
 - 
 
$
 592 
   
 2 
 
$
 277 
Split Rating
   
 1 
   
 1 
   
 - 
   
 - 
   
 - 
Noninvestment Grade
   
 5 
   
 4 
   
 1 
   
 1 
   
 1 
No External Ratings:
                             
 
Internal Investment Grade
   
 91 
   
 - 
   
 91 
   
 2 
   
 24 
 
Internal Noninvestment Grade
   
 58 
   
 11 
   
 47 
   
 1 
   
 33 
Total as of March 31, 2013
 
$
 747 
 
$
 16 
 
$
 731 
   
 6 
 
$
 335 
                                 
Total as of December 31, 2012
 
$
 807 
 
$
 13 
 
$
 794 
   
 7 
 
$
 338 

Value at Risk (VaR) Associated with Risk Management Contracts

We use a risk measurement model, which calculates VaR, to measure our commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, as of March 31, 2013, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

The following table shows the end, high, average and low market risk as measured by VaR for the trading portfolio for the periods indicated:

VaR Model

Three Months Ended
 
Twelve Months Ended
March 31, 2013
 
December 31, 2012
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
(in millions)
 
(in millions)
$
 
$
 
$
 
$
 
$
 
$
 
$
 
$

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

As our VaR calculation captures recent price movements, we also perform regular stress testing of the portfolio to understand our exposure to extreme price movements.  We employ a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which
 
24

 
historical price movements translated into the largest potential MTM loss.  We then research the underlying positions, price movements and market events that created the most significant exposure and report the findings to the Risk Executive Committee or the CORC as appropriate.

Interest Rate Risk

We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which our interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on debt outstanding as of March 31, 2013 and December 31, 2012, the estimated EaR on our debt portfolio for the following twelve months was $40 million and $42 million, respectively.

 
25

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2013 and 2012
 (in millions, except per-share and share amounts)
(Unaudited)
               
     
Three Months Ended March 31,
     
2013 
 
2012 
REVENUES
           
Utility Operations
 
$
 3,489 
 
$
 3,363 
Other Revenues
   
 337 
   
 262 
TOTAL REVENUES
   
 3,826 
   
 3,625 
EXPENSES
           
Fuel and Other Consumables Used for Electric Generation
   
 1,031 
   
 1,053 
Purchased Electricity for Resale
   
 371 
   
 260 
Other Operation
   
 738 
   
 656 
Maintenance
   
 293 
   
 262 
Depreciation and Amortization
   
 420 
   
 423 
Taxes Other Than Income Taxes
   
 218 
   
 217 
TOTAL EXPENSES
   
 3,071 
   
 2,871 
               
OPERATING INCOME
   
 755 
   
 754 
               
Other Income (Expense):
           
Interest and Investment Income
   
 3 
   
 2 
Carrying Costs Income
   
 4 
   
 20 
Allowance for Equity Funds Used During Construction
   
 15 
   
 23 
Interest Expense
   
 (232)
   
 (229)
               
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
   
 545 
   
 570 
               
Income Tax Expense
   
 195 
   
 189 
Equity Earnings of Unconsolidated Subsidiaries
   
 14 
   
 9 
               
NET INCOME
   
 364 
   
 390 
               
Net Income Attributable to Noncontrolling Interests
   
 1 
   
 1 
               
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
 363 
 
$
 389 
               
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
   
485,823,668 
   
483,828,101 
               
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
           
 
SHAREHOLDERS
 
$
 0.75 
 
$
 0.80 
               
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
   
486,344,036 
   
484,248,868 
               
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
           
 
SHAREHOLDERS
 
$
 0.75 
 
$
 0.80 
               
CASH DIVIDENDS DECLARED PER SHARE
 
$
 0.47 
 
$
 0.47 
               
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 32.

 
26

 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2013 and 2012
(in millions)
(Unaudited)
               
     
Three Months Ended March 31,
     
2013 
 
2012 
Net Income
 
$
 364 
 
$
 390 
               
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
           
Cash Flow Hedges, Net of Tax of $13 and $6 in 2013 and 2012, Respectively
   
 24 
   
 (11)
Securities Available for Sale, Net of Tax of $1 and $1 in 2013 and 2012, Respectively
   
 1 
   
 2 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $3 and $4 in 2013
           
 
and 2012, Respectively
   
 6 
   
 7 
               
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
   
 31 
   
 (2)
               
TOTAL COMPREHENSIVE INCOME
   
 395 
   
 388 
               
Total Comprehensive Income Attributable to Noncontrolling Interests
   
 1 
   
 1 
             
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
           
 
COMMON SHAREHOLDERS
 
$
 394 
 
$
 387 
               
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 32.

 
27

 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Three Months Ended March 31, 2013 and 2012
(in millions)
(Unaudited)
                                               
 
AEP Common Shareholders
       
 
Common Stock
         
Accumulated
       
                 
Other
       
         
Paid-in
 
Retained
 
Comprehensive
 
Noncontrolling
   
 
Shares
 
Amount
 
Capital
 
Earnings
 
Income (Loss)
 
Interests
 
Total
TOTAL EQUITY – DECEMBER 31, 2011
 
 504 
 
$
 3,274 
 
$
 5,970 
 
$
 5,890 
 
$
 (470)
 
$
 1 
 
$
 14,665 
                                         
Issuance of Common Stock
 
 1 
   
 6 
   
 25 
                     
 31 
Common Stock Dividends
                   
 (228)
         
 (1)
   
 (229)
Other Changes in Equity
             
 3 
   
 (1)
               
 2 
Net Income
                   
 389 
         
 1 
   
 390 
Other Comprehensive Loss
                         
 (2)
         
 (2)
TOTAL EQUITY – MARCH 31, 2012
 
 505 
 
$
 3,280 
 
$
 5,998 
 
$
 6,050 
 
$
 (472)
 
$
 1 
 
$
 14,857 
                                         
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 
                                         
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 32.

 
28

 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2013 and December 31, 2012
(in millions)
(Unaudited)
 
               
March 31,
 
December 31,
   
2013 
 
2012 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
 179 
 
$
 279 
Other Temporary Investments
           
 
(March 31, 2013 and December 31, 2012 Amounts Include $247 and $311, Respectively, Related to Transition Funding and EIS)
   
 261 
   
 324 
Accounts Receivable:
           
 
Customers
   
 679 
   
 685 
 
Accrued Unbilled Revenues
   
 210 
   
 195 
 
Pledged Accounts Receivable – AEP Credit
   
 884 
   
 856 
 
Miscellaneous
   
 133 
   
 171 
 
Allowance for Uncollectible Accounts
   
 (37)
   
 (36)
   
Total Accounts Receivable
   
 1,869 
   
 1,871 
Fuel
   
 839 
   
 844 
Materials and Supplies
   
 681 
   
 675 
Risk Management Assets
   
 162 
   
 191 
Regulatory Asset for Under-Recovered Fuel Costs
   
 91 
   
 88 
Margin Deposits
   
 74 
   
 76 
Prepayments and Other Current Assets
   
 241 
   
 241 
TOTAL CURRENT ASSETS
   
 4,397 
   
 4,589 
             
PROPERTY, PLANT AND EQUIPMENT
           
Electric:
           
 
Generation
   
 26,389 
   
 26,279 
 
Transmission
   
 9,902 
   
 9,846 
 
Distribution
   
 15,720 
   
 15,565 
Other Property, Plant and Equipment (Including Nuclear Fuel and Coal Mining)
   
 3,986 
   
 3,945 
Construction Work in Progress
   
 2,078 
   
 1,819 
Total Property, Plant and Equipment
   
 58,075 
   
 57,454 
Accumulated Depreciation and Amortization
   
 18,945 
   
 18,691 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
   
 39,130 
   
 38,763 
             
OTHER NONCURRENT ASSETS
           
Regulatory Assets
   
 5,087 
   
 5,106 
Securitized Transition Assets
   
 2,065 
   
 2,117 
Spent Nuclear Fuel and Decommissioning Trusts
   
 1,788 
   
 1,706 
Goodwill
   
 91 
   
 91 
Long-term Risk Management Assets
   
 341 
   
 368 
Deferred Charges and Other Noncurrent Assets
   
 1,651 
   
 1,627 
TOTAL OTHER NONCURRENT ASSETS
   
 11,023 
   
 11,015 
             
TOTAL ASSETS
 
$
 54,550 
 
$
 54,367 
             
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 32.
 
 
 
29

 
             
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 2013 and December 31, 2012
(dollars in millions)
(Unaudited)
 
               
March 31,
 
December 31,
   
2013 
 
2012 
CURRENT LIABILITIES
           
Accounts Payable
 
$
 1,004 
 
$
 1,169 
Short-term Debt:
           
 
Securitized Debt for Receivables - AEP Credit
     
 646 
   
 657 
 
Other Short-term Debt
     
 661 
   
 324 
   
Total Short-term Debt
     
 1,307 
   
 981 
Long-term Debt Due Within One Year
           
 
(March 31, 2013 and December 31, 2012 Amounts Include $365 and $367, Respectively, Related to Transition Funding, DCC Fuel and Sabine)
   
 1,674 
   
 2,171 
Risk Management Liabilities
   
 94 
   
 155 
Customer Deposits
   
 299 
   
 316 
Accrued Taxes
   
 727 
   
 747 
Accrued Interest
   
 241 
   
 269 
Regulatory Liability for Over-Recovered Fuel Costs
   
 18 
   
 47 
Other Current Liabilities
   
 811 
   
 968 
TOTAL CURRENT LIABILITIES
   
 6,175 
   
 6,823 
             
NONCURRENT LIABILITIES
           
Long-term Debt
           
 
(March 31, 2013 and December 31, 2012 Amounts Include $2,098 and $2,227, Respectively, Related to Transition Funding, DCC Fuel and Sabine)
   
 15,899 
   
 15,586 
Long-term Risk Management Liabilities
   
 185 
   
 214 
Deferred Income Taxes
   
 9,556 
   
 9,252 
Regulatory Liabilities and Deferred Investment Tax Credits
   
 3,625 
   
 3,544 
Asset Retirement Obligations
   
 1,727 
   
 1,696 
Employee Benefits and Pension Obligations
   
 1,049 
   
 1,075 
Deferred Credits and Other Noncurrent Liabilities
   
 913 
   
 940 
TOTAL NONCURRENT LIABILITIES
   
 32,954 
   
 32,307 
             
TOTAL LIABILITIES
   
 39,129 
   
 39,130 
             
Rate Matters (Note 3)
           
Commitments and Contingencies (Note 4)
           
             
EQUITY
           
Common Stock – Par Value – $6.50 Per Share:
           
     
2013 
 
2012 
             
 
Shares Authorized
600,000,000 
 
600,000,000 
             
 
Shares Issued
506,356,262 
 
506,004,962 
             
(20,336,592 Shares were Held in Treasury as of March 31, 2013 and December 31, 2012)
   
 3,291 
   
 3,289 
Paid-in Capital
   
 6,066 
   
 6,049 
Retained Earnings
   
 6,370 
   
 6,236 
Accumulated Other Comprehensive Income (Loss)
   
 (306)
   
 (337)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY
   
 15,421 
   
 15,237 
             
Noncontrolling Interests
   
 - 
   
 - 
             
TOTAL EQUITY
   
 15,421 
   
 15,237 
             
TOTAL LIABILITIES AND EQUITY
 
$
 54,550 
 
$
 54,367 
             
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 32.

 
30

 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2013 and 2012
(in millions)
(Unaudited)
 
       
Three Months Ended March 31,
   
2013 
 
2012 
OPERATING ACTIVITIES
           
Net Income
 
$
 364 
 
$
 390 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
           
 
Depreciation and Amortization
   
 420 
   
 423 
 
Deferred Income Taxes
   
 246 
   
 261 
 
Carrying Costs Income
   
 (4)
   
 (20)
 
Allowance for Equity Funds Used During Construction
   
 (15)
   
 (23)
 
Mark-to-Market of Risk Management Contracts
   
 34 
   
 10 
 
Amortization of Nuclear Fuel
   
 34 
   
 34 
 
Property Taxes
   
 (51)
   
 (49)
 
Fuel Over/Under-Recovery, Net
   
 (4)
   
 112 
 
Change in Other Noncurrent Assets
   
 (13)
   
 (59)
 
Change in Other Noncurrent Liabilities
   
 17 
   
 (47)
 
Changes in Certain Components of Working Capital:
           
   
Accounts Receivable, Net
   
 (4)
   
 207 
   
Fuel, Materials and Supplies
   
 (1)
   
 (126)
   
Accounts Payable
   
 (3)
   
 (26)
   
Accrued Taxes, Net
   
 (69)
   
 (30)
   
Other Current Assets
   
 (16)
   
 (15)
   
Other Current Liabilities
   
 (179)
   
 (166)
Net Cash Flows from Operating Activities
   
 756 
   
 876 
             
INVESTING ACTIVITIES
           
Construction Expenditures
   
 (843)
   
 (741)
Change in Other Temporary Investments, Net
   
 75 
   
 79 
Purchases of Investment Securities
   
 (196)
   
 (353)
Sales of Investment Securities
   
 168 
   
 334 
Acquisitions of Nuclear Fuel
   
 (47)
   
 (11)
Acquisitions of Assets/Businesses
   
 (2)
   
 (85)
Insurance Proceeds Related to Cook Plant Fire
   
 72 
   
 - 
Proceeds from Sales of Assets
   
 1 
   
 8 
Other Investing Activities
   
 - 
   
 (23)
Net Cash Flows Used for Investing Activities
   
 (772)
   
 (792)
             
FINANCING ACTIVITIES
           
Issuance of Common Stock, Net
   
 15 
   
 31 
Issuance of Long-term Debt
   
 671 
   
 1,132 
Commercial Paper and Credit Facility Borrowings
   
 17 
   
 21 
Change in Short-term Debt, Net
   
 329 
   
 (583)
Retirement of Long-term Debt
   
 (858)
   
 (339)
Commercial Paper and Credit Facility Repayments
   
 (20)
   
 (38)
Principal Payments for Capital Lease Obligations
   
 (16)
   
 (18)
Dividends Paid on Common Stock
   
 (230)
   
 (229)
Other Financing Activities
   
 8 
   
 4 
Net Cash Flows Used for Financing Activities
   
 (84)
   
 (19)
             
Net Increase (Decrease) in Cash and Cash Equivalents
   
 (100)
   
 65 
Cash and Cash Equivalents at Beginning of Period