AEP 2014 3Q 10Q


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended September 30, 2014
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____
Commission
 
Registrants; States of Incorporation;
 
I.R.S. Employer
File Number
 
Address and Telephone Number
 
Identification Nos.
 
 
 
 
 
1-3525
 
AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)
 
13-4922640
1-3457
 
APPALACHIAN POWER COMPANY (A Virginia Corporation)
 
54-0124790
1-3570
 
INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)
 
35-0410455
1-6543
 
OHIO POWER COMPANY (An Ohio Corporation)
 
31-4271000
0-343
 
PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)
 
73-0410895
1-3146
 
SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)
 
72-0323455
 
 
1 Riverside Plaza, Columbus, Ohio 43215-2373
 
 
 
 
Telephone (614) 716-1000
 
 
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
 
 
 
 
 
 
Yes
X
 
No
 
 
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate websites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).
 
 
 
 
 
 
Yes
X
 
No
 
 
Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
X
 
Accelerated filer
 
 
 
 
 
 
 
 
Non-accelerated filer
 
 
Smaller reporting company
 
 
Indicate by check mark whether Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers or smaller reporting companies.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
 
 
Accelerated filer
 
 
 
 
 
 
 
 
Non-accelerated filer
X
 
Smaller reporting company
 
 
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
 
 
 
 
 
 
Yes
 
 
No
X
 
Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.





 
Number of shares
of common stock
outstanding of the
registrants as of
 
October 23, 2014
 
 
American Electric Power Company, Inc.
489,240,481

 
($6.50 par value)

Appalachian Power Company
13,499,500

 
(no par value)

Indiana Michigan Power Company
1,400,000

 
(no par value)

Ohio Power Company
27,952,473

 
(no par value)

Public Service Company of Oklahoma
9,013,000

 
($15 par value)

Southwestern Electric Power Company
7,536,640

 
($18 par value)





AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
September 30, 2014
 
 
 
 
 
 
 
 
 
Page
 
 
 
 
Number
Glossary of Terms
 
 
 
 
 
Forward-Looking Information
 
 
 
 
 
Part I. FINANCIAL INFORMATION
 
 
 
 
 
 
 
Items 1, 2, 3 and 4 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Controls and Procedures:
 
 
 
 
 
 
American Electric Power Company, Inc. and Subsidiary Companies:
 
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Condensed Consolidated Financial Statements
 
Index of Condensed Notes to Condensed Consolidated Financial Statements
 
 
 
 
 
Appalachian Power Company and Subsidiaries:
 
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
Condensed Consolidated Financial Statements
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
 
 
 
 
Indiana Michigan Power Company and Subsidiaries:
 
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
Condensed Consolidated Financial Statements
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
 
 
 
 
Ohio Power Company and Subsidiaries:
 
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
Condensed Consolidated Financial Statements
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
 
 
 
 
Public Service Company of Oklahoma:
 
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
Condensed Financial Statements
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
 
 
 
 
Southwestern Electric Power Company Consolidated:
 
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
Condensed Consolidated Financial Statements
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
 
 
 
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
 
 
 
 
Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries
 
 
 
 
 
Controls and Procedures




 
 
 
 
 
Part II.  OTHER INFORMATION
 
 
 
 
 
 
 
Item 1.
  Legal Proceedings
 
Item 1A.
  Risk Factors
 
Item 2.
  Unregistered Sales of Equity Securities and Use of Proceeds
 
Item 4.
  Mine Safety Disclosures
 
Item 5.
  Other Information
 
Item 6.
  Exhibits:
 
 
 
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
 
 
 
 
 
 
 
 
 
 
 
 
This combined Form 10-Q is separately filed by American Electric Power Company, Inc., Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company.  Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.




GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
Term
 
Meaning
 
 
 
AEGCo
 
AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent
 
American Electric Power Company, Inc., an electric utility holding company.
AEP Consolidated
 
AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit
 
AEP Credit, Inc., a consolidated variable interest entity of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East Companies
 
APCo, I&M, KPCo and OPCo.
AEP Energy
 
AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.
AEP System
 
American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP Transmission Holdco
 
AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEPSC
 
American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo
 
AEP Transmission Company, LLC, a subsidiary of AEP Transmission Holdco and an intermediate holding company that owns seven wholly-owned transmission companies.
AGR
 
AEP Generation Resources Inc., a nonregulated AEP subsidiary in the Generation & Marketing segment.
AFUDC
 
Allowance for Funds Used During Construction.
AOCI
 
Accumulated Other Comprehensive Income.
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
Appalachian Consumer Rate Relief Funding
 
Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
ASU
 
Accounting Standards Update.
CAA
 
Clean Air Act.
CLECO
 
Central Louisiana Electric Company, a nonaffiliated utility company.
CO2
 
Carbon dioxide and other greenhouse gases.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CRES provider
 
Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service.
CSPCo
 
Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
CWIP
 
Construction Work in Progress.
DCC Fuel
 
DCC Fuel II LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI LLC, consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC
 
Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
EIS
 
Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entity of AEP.
ENEC
 
Expanded Net Energy Charge.
Energy Supply
 
AEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
ERCOT
 
Electric Reliability Council of Texas regional transmission organization.
ESP
 
Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.

i



Term
 
Meaning
 
 
 
ETT
 
Electric Transmission Texas, LLC, an equity interest joint venture between AEP and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
FAC
 
Fuel Adjustment Clause.
FASB
 
Financial Accounting Standards Board.
Federal EPA
 
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
FGD
 
Flue Gas Desulfurization or scrubbers.
FTR
 
Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP
 
Accounting Principles Generally Accepted in the United States of America.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IEU
 
Industrial Energy Users-Ohio.
IGCC
 
Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement
 
An agreement by and among APCo, I&M, KPCo and OPCo, which defined the sharing of costs and benefits associated with their respective generation plants. This agreement was terminated January 1, 2014.
IRS
 
Internal Revenue Service.
IURC
 
Indiana Utility Regulatory Commission.
KGPCo
 
Kingsport Power Company, an AEP electric utility subsidiary.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
 
Kentucky Public Service Commission.
KWh
 
Kilowatthour.
LPSC
 
Louisiana Public Service Commission.
MISO
 
Midwest Independent Transmission System Operator.
MMBtu
 
Million British Thermal Units.
MPSC
 
Michigan Public Service Commission.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWh
 
Megawatthour.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NSR
 
New Source Review.
OCC
 
Corporation Commission of the State of Oklahoma.
Ohio Phase-in-Recovery Funding
 
Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OPEB
 
Other Postretirement Benefit Plans.
Operating Agreement
 
Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third party sales. AEPSC acts as the agent.
OTC
 
Over the counter.
OVEC
 
Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PIRR
 
Phase-In Recovery Rider.
PJM
 
Pennsylvania – New Jersey – Maryland regional transmission organization.
PM
 
Particulate Matter.
POLR
 
Provider of Last Resort revenues.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.

ii



Term
 
Meaning
 
 
 
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants; APCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
 
A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.  AEGCo and I&M jointly-own Unit 1.  In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
RPM
 
Reliability Pricing Model.
RSR
 
Retail Stability Rider.
RTO
 
Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine
 
Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC
 
U.S. Securities and Exchange Commission.
SEET
 
Significantly Excessive Earnings Test.
SIA
 
System Integration Agreement, effective June 15, 2000, as amended, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF
 
Spent Nuclear Fuel.
SO2
 
Sulfur dioxide.
SPP
 
Southwest Power Pool regional transmission organization.
SSO
 
Standard service offer.
Stall Unit
 
J. Lamar Stall Unit at Arsenal Hill Plant, a 534 MW natural gas unit owned by SWEPCo.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC
 
AEP Texas Central Company, an AEP electric utility subsidiary.
Texas Restructuring Legislation
 
Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC
 
AEP Texas North Company, an AEP electric utility subsidiary.
Transition Funding
 
AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.
Transource Energy
 
Transource Energy, LLC, a consolidated variable interest entity formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.
Transource Missouri
 
A 100% wholly-owned subsidiary of Transource Energy.
Turk Plant
 
John W. Turk, Jr. Plant, a 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
Utility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE
 
Variable Interest Entity.
Virginia SCC
 
Virginia State Corporation Commission.
WPCo
 
Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC
 
Public Service Commission of West Virginia.
 

iii



FORWARD-LOOKING INFORMATION

This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2013 Annual Report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:
Ÿ
The economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory.
Ÿ
Inflationary or deflationary interest rate trends.
Ÿ
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.
Ÿ
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.
Ÿ
Electric load, customer growth and the impact of retail competition.
Ÿ
Weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs.
Ÿ
Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
Ÿ
Availability of necessary generation capacity and the performance of our generation plants.
Ÿ
Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
Ÿ
Our ability to build or acquire generation capacity and transmission lines and facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs.
Ÿ
New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation, cost recovery and/or profitability of our generation plants and related assets.
Ÿ
Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
Ÿ
A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
Ÿ
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.
Ÿ
Resolution of litigation.
Ÿ
Our ability to constrain operation and maintenance costs.
Ÿ
Our ability to develop and execute a strategy based on a view regarding prices of electricity and other energy-related commodities.
Ÿ
Prices and demand for power that we generate and sell at wholesale.
Ÿ
Changes in technology, particularly with respect to new, developing, alternative or distributed sources of generation.
Ÿ
Our ability to recover through rates or market prices any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.

iv



Ÿ
Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.
Ÿ
Changes in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP.
Ÿ
The transition to market for generation in Ohio, including the implementation of ESPs.
Ÿ
Our ability to successfully and profitably manage our separate competitive generation assets.
Ÿ
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
Ÿ
Actions of rating agencies, including changes in the ratings of our debt.
Ÿ
The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.
Ÿ
Accounting pronouncements periodically issued by accounting standard-setting bodies.
Ÿ
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.
The forward looking statements of AEP and its Registrant Subsidiaries speak only as of the date of this report or as of the date they are made.  AEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 2013 Annual Report and in Part II of this report.



v





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


EXECUTIVE OVERVIEW

Customer Demand

In comparison to 2013, heating degree days for the nine months ended September 30, 2014 were up 32% in our western region and 20% in our eastern region while cooling degree days were down 7% for the same period in both the eastern and western regions. Our weather-normalized retail sales volumes for the third quarter of 2014 increased by 0.1% from their levels for the third quarter of 2013 and increased by 0.4% for the first nine months of 2014 from their levels for the first nine months of 2013. In comparison to 2013, our industrial sales volume increased 1.2% for the three months ended September 30, 2014 and decreased 0.7% for the nine months ended September 30, 2014. The decrease in industrial sales volume is due mainly to the closure of Ormet, a large aluminum company. Excluding Ormet, our nine months ended September 30, 2014 industrial sales volumes increased 3.8% over the nine months ended September 30, 2013.

Ohio Electric Security Plan Filings

2009 - 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. As of September 30, 2014, OPCo’s net deferred fuel balance was $395 million, excluding unrecognized equity carrying costs. Decisions from the Supreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs balance up to the full amount.
 
June 2012 - May 2015 Ohio ESP Including Capacity Charge

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

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and is $150/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50/MWh through May 2014 and is currently collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR. As of September 30, 2014, OPCo’s incurred deferred capacity costs balance was $409 million, including debt carrying costs.


1



In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. In February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. In May and September 2014, OPCo conducted energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for the remaining 40% of the SSO load for delivery from January 2015 through May 2015. OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In May 2014, an independent auditor was selected by the PUCO and an audit of the recovery of the fixed fuel costs began in June 2014. In October 2014, the independent auditor filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88 capacity charge, the independent auditor recommends a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and intends to oppose the findings in the audit report.

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

Proposed June 2015 - May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM capacity and energy auction-based generation through OPCo. The proposal also includes a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based purchase power agreement. In May 2014, intervenors and the PUCO staff filed testimony that provided various recommendations including the rejection and/or modification of various riders, including the Distribution Investment Rider and the proposed PPA. Hearings at the PUCO in the ESP case were held in June 2014. Additionally, in July 2014, OPCo submitted a separate application to continue the RSR established in the June 2012 - May 2015 ESP to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. In October 2014, OPCo filed a separate application with the PUCO to propose a new PPA for inclusion in the PPA rider, discussed above. The new PPA would include an additional 2,671 MW to be purchased from AGR over the life of the respective generating units.

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

2012 Texas Base Rate Case

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

2




2012 Louisiana Formula Rate Filing

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

2014 Oklahoma Base Rate Case

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

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

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a biennial generation and distribution base rate case with the Virginia SCC. In accordance with a Virginia statute, APCo did not request an increase in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to the change in the expected service life of certain plants. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to IGCC and other deferred costs.

In August 2014, the Virginia SCC staff and intervenors filed testimony concluding that APCo's adjusted earned rate of return on common equity for 2012 and 2013, reflecting their recommended adjustments, was above the allowed threshold. Recommendations included (a) refunds to customers ranging from $15 million to $22 million, (b) the write-off of certain APCo assets, including IGCC pre-construction costs and previously approved 2009 storm costs, totaling $27 million and (c) $38 million in increased depreciation expense annually, retroactive to January 1, 2014, primarily related to accelerating depreciation on APCo generation assets to be retired in the second quarter of 2015. Hearings at the Virginia SCC were held in September 2014. A decision is expected in November 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 Virginia Biennial Base Rate Case” section of Note 4.


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2014 West Virginia Base Rate Case

In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $181 million, based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates and requested recovery of $89 million over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $45 million annually to recover vegetation management costs, including a return on capital investment. In October 2014, the WVPSC approved APCo's motion to revise the procedural schedule which included the extension of the intervention period to November 2014 and a delay in the implementation of new rates from April 2015 to May 2015. Hearings at the WVPSC are scheduled for January 2015. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 West Virginia Base Rate Case” section of Note 4.

Plant Transfer

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a cost-of-service basis. West Virginia generally allows for timely recovery of fuel costs through an expanded net energy cost which trues-up to actual expenses. In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo. In June 2014, the FERC issued an order approving AGR and WPCo's request to transfer AGR’s one-half interest in the Mitchell Plant to WPCo.

In October 2014, a stipulation agreement between APCo, WPCo, the WVPSC staff and intervenors in the case was filed with the WVPSC. The stipulation agreement recommended approval for WPCo to acquire, at net book value, the one-half interest in the Mitchell Plant, excluding $20 million of certain assets, which will be paid by WPCo and recovered as a regulatory asset over the life of the plant. Additionally, the agreement stated that 82.5% of the costs associated with the acquired interest will be reflected in rates effective from the date of the transfer via a surcharge with an offset in ENEC revenues. The remaining 17.5% of the costs associated with the acquired interest is to be included in rates by January 2020. The agreement also proposed that WPCo share the energy margins for 82.5% of the plant’s output with ratepayers and that WPCo retain all of the energy margins from sales into the wholesale market on the remaining 17.5%, to offset fixed costs associated with this portion, until the remaining portion is approved for inclusion in rates. Management anticipates an order related to the proposed plant transfer will be issued in the fourth quarter of 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “Plant Transfer” section of APCo Rate Matters in Note 4.

Kentucky Fuel Adjustment Clause Review

In August 2014, the KPSC issued an order initiating a review of KPCo's FAC from November 2013 through April 2014. An intervenor has requested and received a revised procedural schedule to determine if the allocation of fuel costs has been applied appropriately. In October 2014, intervenors filed testimony that recommended the KPSC direct KPCo to modify its fuel allocation methodology and order a refund to customers of approximately $13 million, plus carrying charges at a weighted average cost of capital, related to the period January 1, 2014 through April 30, 2014. A hearing at the KPSC is scheduled for November 2014. Management believes the methodology used to determine fuel costs is appropriate and intends to oppose the recommendations filed by intervenors. If the KPSC directs KPCo to modify its fuel allocation methodology, it could affect the allocation of costs for all periods beginning January 2014, and if any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “Kentucky Fuel Adjustment Clause Review” section of Note 4.


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PJM Capacity Market

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

June 2014 through May 2015
 
 
125.99

June 2015 through May 2016
 
 
136.00

June 2016 through May 2017
 
 
59.37

June 2017 through May 2018
 
 
120.00


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

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

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

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC. As of September 30, 2014, SWEPCo has incurred costs of $112 million and has contractual construction obligations of $84 million related to these projects.  SWEPCo will seek to recover these project costs from customers through filings at the state commissions and FERC. These environmental projects could be adversely impacted by pending carbon emission regulations.  See "CO2 Regulation" section of “Environmental Issues” below.  As of September 30, 2014, the net book value of Welsh Plant, Units 1 and 3 was $335 million, before cost of removal, including materials and supplies inventory and CWIP.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 


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LITIGATION

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. We assess the probability of loss for each contingency and accrue a liability for cases that have a probable likelihood of loss if the loss can be estimated. For details on our regulatory proceedings and pending litigation see Note 4 - Rate Matters, Note 6 - Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2013 Annual Report. Additionally, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies included herein. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation

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

ENVIRONMENTAL ISSUES

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

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

See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2013 Annual Report. We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If we are unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.


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Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System. We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of September 30, 2014, the AEP System had a total generating capacity of 37,600 MWs, of which 23,700 MWs are coal-fired. We continue to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on our generating facilities. Based upon our estimates, investment to meet these requirements ranges from approximately $3 billion to $3.5 billion through 2020. Several proposed regulations issued during 2014, including CO2 and the Clean Water Act, are currently under review and we cannot currently predict the impact these programs may have on future resource plans or our existing generating fleet; however, the costs may be substantial. These amounts include investments to convert some of our coal generation to natural gas. If natural gas conversion is not completed, the units could be retired sooner than planned.

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

Subject to the factors listed above and based upon our continuing evaluation, we intend to retire the following plants or units of plants before or during 2016:
 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs) 
AGR
 
Kammer Plant
 
630

AGR
 
Muskingum River Plant
 
1,440

AGR
 
Picway Plant
 
100

APCo
 
Clinch River Plant, Unit 3
 
235

APCo
 
Glen Lyn Plant
 
335

APCo
 
Kanawha River Plant
 
400

APCo/AGR
 
Sporn Plant
 
600

I&M
 
Tanners Creek Plant
 
995

KPCo
 
Big Sandy Plant, Unit 2
 
800

PSO
 
Northeastern Station, Unit 4
 
470

SWEPCo
 
Welsh Plant, Unit 2
 
528

Total
 
 
 
6,533


As of September 30, 2014, the net book value of the AGR units listed above was zero. The net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the regulated plants in the table above was $973 million.

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

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

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

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may close early, we are seeking regulatory recovery of remaining net book values. To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows and impact financial condition.

Clean Air Act Requirements

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

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

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

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

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

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

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


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Cross-State Air Pollution Rule (CSAPR)

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

Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit. Several of the petitioners filed motions to stay the implementation of the rule pending judicial review. In 2011, the court granted the motions for stay. In 2012, the court issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the CAIR until a replacement rule is finalized. The majority determined that the CAA does not allow the Federal EPA to “overcontrol” emissions in an upwind state and that the Federal EPA exceeded its statutory authority by failing to allow states an opportunity to develop their own implementation plans before issuing a FIP. The Federal EPA and other respondents filed petitions for rehearing but in January 2013, the U.S. Court of Appeals for the District of Columbia Circuit denied all petitions for rehearing. The petition for further review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013. In April 2014, the U.S. Supreme Court issued a decision reversing in part the decision of the U.S. Court of Appeals for the District of Columbia Circuit and remanding the case for further proceedings consistent with the opinion. The parties have filed motions to govern further proceedings. The Federal EPA has filed a motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. Until the court acts on this motion, CAIR will remain in effect. Separate appeals of the Error Corrections Rule and the further revisions have been filed but no briefing schedules have been established. We cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of several nonmercury metals) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis. In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. The effective date of the final rule was April 16, 2012 and compliance is required within three years. Petitions for administrative reconsideration and judicial review were filed. In 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards. The Federal EPA issued revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions in March 2013. The Federal EPA is still considering additional changes to the start-up and shut down provisions. In April 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the April 2012 final rule. Industry and environmental groups filed petitions for further review in the U.S. Supreme Court.

The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and allows operators to exclude periods of startup and shutdown from the emissions averaging periods. The compliance time frame remains a serious concern. We have obtained a one-year administrative extension at several units to facilitate the installation of controls or to avoid a serious reliability problem. In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades. We remain concerned about the availability

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of compliance extensions, the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines and the lack of coordination among the Mercury and Air Toxics Standards schedule and other environmental requirements.

CO2 Regulation

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

The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from modified and reconstructed electric generating units (EGUs) and to issue guidelines for existing EGUs before June 2014, to finalize those standards by June 2015 and to require states to submit revisions to their implementation plans including such standards no later than June 2016. The President directed the Federal EPA, in developing this proposal, to directly engage states, leaders in the power sector, labor leaders and other stakeholders, to tailor the regulations to reduce costs, to develop market-based instruments and allow regulatory flexibilities and “assure that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power.” The guidelines use a “portfolio” approach to reducing emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units, expanding renewable resources and increasing customer energy efficiency. The Federal EPA issued proposed guidelines establishing state goals for CO2 emissions from existing EGUs and comments are due December 1, 2014. The Federal EPA also issued proposed regulations governing emissions of CO2 from modified and reconstructed EGUs in June 2014 and comments are due in October 2014. The standards for modified and reconstructed units include several options, including use of historic baselines or energy efficiency audits to establish source-specific CO2 emission rates or to limit CO2 emissions to no more than 1,900 pounds per MWh at larger coal units and 2,100 pounds per MWh at smaller coal units. These proposed regulations are currently under review. We cannot currently predict the impact these programs may have on future resource plans or our existing generating fleet, but the costs may be substantial.

In 2012, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO2 emissions from new motor vehicles and its plan to phase in regulation of CO2 emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. In 2012, the U.S. Court of Appeals for the District of Columbia Circuit denied a petition for rehearing. In June 2014, the U.S. Supreme Court determined that the Federal EPA was not compelled to regulate CO2 emissions from stationary sources under the Title V or PSD programs as a result of its adoption of the motor vehicle standards, but that sources otherwise required to obtain a PSD permit may be required to perform a Best Available Control Technology analysis for CO2 emissions if they exceed a reasonable level. The Federal EPA must undertake additional rulemaking to implement the court’s decision and establish an appropriate level.

Coal Combustion Residual Rule

In 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants.  The rule contains two alternative proposals. One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management. Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule. In 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data

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received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment. In 2013, the Federal EPA also issued a notice of data availability requesting comments on a narrow set of issues.

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

In February 2014, the Federal EPA completed a risk evaluation of the beneficial uses of coal fly ash in concrete and FGD gypsum in wallboard and concluded that the Federal EPA supports these beneficial uses.  Currently, approximately 40% of the coal ash and other residual products from our generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses. Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes. In addition, we currently use surface impoundments and landfills to manage these materials at our generating facilities. We will incur significant costs to upgrade or close and replace these existing facilities under the proposed solid waste management alternative. Regulation of these materials as hazardous wastes would significantly increase these costs. As the rule is not final, we are unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

Clean Water Act Regulations

In 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress. In 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments. The final rule was released by the Federal EPA in May 2014 and affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to comply with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures at facilities withdrawing more than 125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, are not expected to require any technology changes. Facilities subject to both the impingement standard and site-specific entrainment studies will typically be given at least three years to conduct and submit the results of those studies to the permit agency. Compliance timeframes will then be established by the permit agency through each facility’s National Pollutant Discharge Elimination System (NPDES) permit for installation of any required technology changes, as those permits are renewed over the next five to eight years. Petitions for review of the final rule have been filed by industry and environmental groups and have been consolidated in the U.S. Court of Appeals for the Fourth Circuit.

In addition, the Federal EPA issued an information collection request and is developing revised effluent limitation guidelines for electricity generating facilities. A proposed rule was signed in April 2013 with a final rule expected in September 2015. The Federal EPA proposed eight options of increasing stringency and cost for fly ash and bottom ash transport water, scrubber wastewater, leachate from coal combustion byproduct landfills and impoundments and other wastewaters associated with coal-fired generating units, with four labeled preferred options. Certain of the Federal EPA's preferred options have already been implemented or are part of our long-term plans. We continue to review the proposal in detail to evaluate whether our plants are currently meeting the proposed limitations, what technologies have been incorporated into our long-range plans and what additional costs might be incurred if the Federal EPA's most stringent options were adopted. We submitted detailed comments to the Federal EPA in September 2013 and participated in comments filed by various organizations of which we are members.


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

Climate Change

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

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

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

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

For additional information on climate change, other environmental issues and the actions we are taking to address potential impacts, see Part I of the 2013 Form 10-K under the headings entitled “Environmental and Other Matters” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

RESULTS OF OPERATIONS

SEGMENTS

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

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


12



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

Vertically Integrated Utilities

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

Transmission and Distribution Utilities

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

AEP Transmission Holdco

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

Generation & Marketing

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

AEP River Operations

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

The table below presents Earnings Attributable to AEP Common Shareholders by segment for the three and nine months ended September 30, 2014 and 2013.
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions)
Vertically Integrated Utilities
$
219

 
$
173

 
$
651

 
$
505

Transmission and Distribution Utilities
92

 
119

 
279

 
281

AEP Transmission Holdco
43

 
22

 
114

 
53

Generation & Marketing
117

 
112

 
378

 
188

AEP River Operations
11

 
(1
)
 
17

 
(12
)
Corporate and Other (a)
11

 
8

 
4

 
119

Earnings Attributable to AEP Common Shareholders
$
493

 
$
433

 
$
1,443

 
$
1,134

(a)
While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

13




AEP CONSOLIDATED

Third Quarter of 2014 Compared to Third Quarter of 2013

Earnings Attributable to AEP Common Shareholders increased from $433 million in 2013 to $493 million in 2014 primarily due to:

Impairments during the third quarter of 2013 related to the following:
A decision by the PUCT determining that AFUDC on the Turk Plant was included in the Texas capital cost cap.
A decision from the KPSC disallowing scrubber costs on KPCo's Big Sandy Plant.
Successful rate proceedings in our various jurisdictions.
An increase in transmission investment which resulted in higher revenues and income.

These increases were partially offset by:

A decrease in weather-related usage.
An increase in plant maintenance.
An increase in vegetation management expenses.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

Earnings Attributable to AEP Common Shareholders increased from $1.1 billion in 2013 to $1.4 billion in 2014 primarily due to:

Impairments during 2013 related to the following:
Muskingum River Plant, Unit 5.
A decision by the PUCT determining that AFUDC on the Turk Plant was included in the Texas capital cost cap.
A decision from the KPSC disallowing scrubber costs on KPCo's Big Sandy Plant.
Successful rate proceedings in our various jurisdictions.
A net increase in weather-related usage.
Higher market prices and increased sales volumes.
An increase in transmission investment which resulted in higher revenues and income.

These increases were partially offset by:

A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.
An increase in depreciation expense due to increased investments.
An increase in vegetation management expenses.
An increase in plant maintenance.


14



Our results of operations by operating segment are discussed below.

VERTICALLY INTEGRATED UTILITIES
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 Vertically Integrated Utilities
 
2014
 
2013
 
2014
 
2013
 
 
(in millions)
Revenues
 
$
2,450

 
$
2,738

 
$
7,288

 
$
7,555

Fuel and Purchased Electricity
 
1,010

 
1,325

 
3,038

 
3,590

Gross Margin
 
1,440

 
1,413

 
4,250

 
3,965

Other Operation and Maintenance
 
615

 
524

 
1,809

 
1,653

Asset Impairments and Other Related Charges
 

 
144

 

 
144

Depreciation and Amortization
 
257

 
233

 
772

 
702

Taxes Other Than Income Taxes
 
95

 
93

 
278

 
277

Operating Income
 
473

 
419

 
1,391

 
1,189

Interest and Investment Income
 
2

 

 
3

 
7

Carrying Costs Income
 
1

 
5

 
2

 
10

Allowance for Equity Funds Used During Construction
 
12

 
9

 
33

 
27

Interest Expense
 
(133
)
 
(136
)
 
(396
)
 
(408
)
Income Before Income Tax Expense and Equity Earnings
 
355

 
297

 
1,033

 
825

Income Tax Expense
 
135

 
123

 
380

 
318

Equity Earnings of Unconsolidated Subsidiaries
 

 

 
1

 
1

Net Income
 
220

 
174

 
654

 
508

Net Income Attributable to Noncontrolling Interests
 
1

 
1

 
3

 
3

Earnings Attributable to AEP Common Shareholders
 
$
219

 
$
173

 
$
651

 
$
505


Summary of KWh Energy Sales for Vertically Integrated Utilities
 
Three Months Ended 
 September 30,
 
 
Nine Months Ended 
 September 30,
 
 
2014
 
2013
 
 
2014
 
2013
 
 
(in millions of KWhs)
 
Retail:
 

 
 

 
 
 

 
 

 
Residential
8,505

 
9,043

 
 
26,126

 
25,710

 
Commercial
6,743

 
6,910

 
 
18,980

 
18,913

 
Industrial
8,962

 
8,634

 
 
26,319

 
25,602

 
Miscellaneous
608

 
602

 
 
1,740

 
1,717

 
Total Retail
24,818

 
25,189

 
 
73,165

 
71,942

 
 
 
 
 
 
 
 
 
 
 
Wholesale (a)
8,632

 
NM

(b)
 
27,418

 
NM

(b)

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


15



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

Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
 
(in degree days)
Eastern Region
 

 
 

 
 

 
 

Actual  Heating (a)
2

 
1

 
2,248

 
1,854

Normal  Heating (b)
5

 
6

 
1,736

 
1,741

 
 
 
 
 
 
 
 
Actual  Cooling (c)
559

 
657

 
921

 
1,007

Normal  Cooling (b)
733

 
733

 
1,062

 
1,062

 
 
 
 
 
 
 
 
Western Region
 

 
 

 
 

 
 

Actual  Heating (a)

 

 
1,233

 
1,009

Normal  Heating (b)
1

 
2

 
921

 
923

 
 
 
 
 
 
 
 
Actual  Cooling (c)
1,246

 
1,387

 
1,926

 
2,070

Normal  Cooling (b)
1,399

 
1,396

 
2,109

 
2,106


(a)
Eastern Region and Western Region heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern Region and Western Region cooling degree days are calculated on a 65 degree temperature base.


16



Third Quarter of 2014 Compared to Third Quarter of 2013
Reconciliation of Third Quarter of 2013 to Third Quarter of 2014
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
 
 
 
Third Quarter of 2013
 
$
173

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
23

Off-system Sales
 
15

Transmission Revenues
 
1

Other Revenues
 
(12
)
Total Change in Gross Margin
 
27

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(91
)
Asset Impairments and Other Related Charges
 
144

Depreciation and Amortization
 
(24
)
Taxes Other Than Income Taxes
 
(2
)
Interest and Investment Income
 
2

Carrying Costs Income
 
(4
)
Allowance for Equity Funds Used During Construction
 
3

Interest Expense
 
3

Total Change in Expenses and Other
 
31

 
 
 

Income Tax Expense
 
(12
)
 
 
 
Third Quarter of 2014
 
$
219


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 $23 million primarily due to the following:
The effect of successful rate proceedings in our service territories which include:
APCo - $43 million.
KPCo - $14 million.
For the rate increases described above, $35 million of these increases relate to riders/trackers which have corresponding increases in expense items below.    
These increases were partially offset by:
A $36 million decrease in weather-related usage primarily due to a decrease in cooling degree days.
Margins from Off-system Sales increased $15 million primarily due to changes in margin sharing.
Other Revenues decreased $12 million primarily due to a decrease in barging. This decrease in barging is a result of the River Transportation Division (RTD) no longer serving plants transferred from OPCo to AGR effective December 31, 2013 as a result of corporate separation in Ohio. This decrease in RTD revenue has a corresponding decrease in Other Operation and Maintenance expenses for barging as discussed below.


17



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

Other Operation and Maintenance expenses increased $91 million primarily due to the following:
A $19 million increase in plant outage and maintenance expenses.
A $17 million increase in recoverable expenses, including PJM expenses, currently fully recovered in rate recovery riders/trackers partially offset by RTD expenses for barging activities.
A $17 million increase in employee-related expenses.
An $11 million increase in transmission and distribution expenses primarily due to storms and non-recoverable SPP services.
A $10 million increase in uncollectible accounts primarily due to the favorable resolution of contingencies related to pole attachments in the third quarter of 2013.
A $9 million increase in approved incremental vegetation management expenses.
An $8 million increase due to an accrual for expected environmental remediation costs.
Asset Impairments and Other Related Charges decreased $144 million primarily due to the following:
A $111 million decrease due to the third quarter 2013 write-off of AFUDC on the Turk Plant.
A $33 million decrease due to KPCo's third quarter 2013 write-off of scrubber costs on the Big Sandy Plant and other generation in accordance with the KPSC's October 2013 order.
Depreciation and Amortization expenses increased $24 million primarily due to overall higher depreciable base.
Income Tax Expense increased $12 million primarily due to an increase in pretax book income partially offset by other book/tax differences which are accounted for on a flow-through basis.

18



Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013
Reconciliation of Nine Months Ended September 30, 2013 to Nine Months Ended September 30, 2014
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
 
 
 
Nine Months Ended September 30, 2013
 
$
505

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
186

Off-system Sales
 
121

Transmission Revenues
 
17

Other Revenues
 
(39
)
Total Change in Gross Margin
 
285

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(156
)
Asset Impairments and Other Related Charges
 
144

Depreciation and Amortization
 
(70
)
Taxes Other Than Income Taxes
 
(1
)
Interest and Investment Income
 
(4
)
Carrying Costs Income
 
(8
)
Allowance for Equity Funds Used During Construction
 
6

Interest Expense
 
12

Total Change in Expenses and Other
 
(77
)
 
 
 

Income Tax Expense
 
(62
)
 
 
 

Nine Months Ended September 30, 2014
 
$
651


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 $186 million primarily due to the following:
The effect of successful rate proceedings in our service territories which include:
APCo - $114 million.
KPCo - $41 million.
SWEPCo - $28 million.
I&M - $28 million.
For the rate increases described above, $87 million of these increases relate to riders/trackers which have corresponding increases in expense items below.
A $16 million increase due to favorable weather conditions.
These increases were partially offset by:
A $39 million increase in PJM expenses net of recovery or offsets.
Margins from Off-system Sales increased $121 million primarily due to higher market prices.
Transmission Revenues increased $17 million primarily due to increased investment in the PJM region.
Other Revenues decreased $39 million primarily due to a decrease in barging. This decrease in barging is a result of the RTD no longer serving plants transferred from OPCo to AGR as of December 31, 2013 as a result of corporate separation in Ohio. This decrease in RTD revenue has a corresponding decrease in Other Operation and Maintenance expenses for barging as discussed below.


19



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

Other Operation and Maintenance expenses increased $156 million primarily due to the following:
A $38 million increase in recoverable expenses, including PJM expenses, currently fully recovered in rate recovery riders/trackers partially offset by RTD expenses for barging activities.
A $38 million increase in transmission expenses primarily related to PJM and SPP services.
A $29 million increase in plant outage and maintenance expenses.
A $25 million increase due to an agreement reached to settle an insurance claim in the first quarter of 2013.
A $20 million increase in employee-related expenses.
A $14 million increase in distribution and transmission vegetation management expenses.
These increases were partially offset by:
A $30 million write-off in the first quarter of 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.
Asset Impairments and Other Related Charges decreased $144 million primarily due to the following:
A $111 million decrease due to the third quarter 2013 write-off of AFUDC on the Turk Plant.
A $33 million decrease due to KPCo's third quarter 2013 write-off of scrubber costs on the Big Sandy Plant and other generation in accordance with the KPSC's October 2013 order.
Depreciation and Amortization expenses increased $70 million primarily due to overall higher depreciable base.
Carrying Cost Income decreased $8 million primarily due to the November 2013 securitization of the West Virginia ENEC deferral balance.
Allowance for Equity Funds Used During Construction increased $6 million primarily due to an increase in environmental construction projects.
Interest Expense decreased $12 million primarily due to the following:
A $5 million decrease due to the retirement of KPCo Senior Unsecured Notes in the third quarter of 2013.
A $4 million decrease due to rate approvals in Louisiana and Texas as well as an increase in the debt component of AFUDC due to increased transmission and environmental projects.
Income Tax Expense increased $62 million primarily due to an increase in pretax book income.


20



TRANSMISSION AND DISTRIBUTION UTILITIES
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Transmission and Distribution Utilities
 
2014
 
2013
 
2014
 
2013
 
 
(in millions)
Revenues
 
$
1,231

 
$
1,195

 
$
3,580

 
$
3,393

Fuel and Purchased Electricity
 
377

 
406

 
1,123

 
1,260

Amortization of Generation Deferrals
 
27

 

 
83

 

Gross Margin
 
827

 
789

 
2,374

 
2,133

Other Operation and Maintenance
 
329

 
254

 
920

 
717

Depreciation and Amortization
 
182

 
165

 
499

 
449

Taxes Other Than Income Taxes
 
117

 
118

 
344

 
327

Operating Income
 
199

 
252

 
611

 
640

Interest and Investment Income
 
3

 

 
9

 
1

Carrying Costs Income
 
6

 
3

 
20

 
10

Allowance for Equity Funds Used During Construction
 
3

 
2

 
8

 
4

Interest Expense
 
(68
)
 
(72
)
 
(210
)
 
(219
)
Income Before Income Tax Expense
 
143

 
185

 
438

 
436

Income Tax Expense
 
51

 
66

 
159

 
155

Net Income
 
92

 
119

 
279

 
281

Net Income Attributable to Noncontrolling Interests
 

 

 

 

Earnings Attributable to AEP Common Shareholders
 
$
92

 
$
119

 
$
279

 
$
281


Summary of KWh Energy Sales for Transmission and Distribution Utilities
 
Three Months Ended 
 September 30,
 
 
Nine Months Ended 
 September 30,
 
 
2014
 
2013
 
 
2014
 
2013
 
 
(in millions of KWhs)
 
Retail:
 

 
 

 
 
 

 
 

 
Residential
7,194

 
7,371

 
 
20,280

 
19,589

 
Commercial
6,796

 
6,827

 
 
19,012

 
18,693

 
Industrial
5,489

 
5,648

 
 
16,262

 
17,277

 
Miscellaneous
187

 
195

 
 
540

 
535

 
Total Retail (a)
19,666

 
20,041

 
 
56,094

 
56,094

 
 
 
 
 
 
 
 
 
 
 
Wholesale (b)
575

 
NM

(c)
 
1,727

 
NM

(c)

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


21



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

Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
 
(in degree days)
Eastern Region
 

 
 

 
 

 
 

Actual  Heating (a)
1

 
1

 
2,540

 
2,165

Normal  Heating (b)
7

 
8

 
2,074

 
2,083

 
 
 
 
 
 
 
 
Actual  Cooling (c)
581

 
645

 
943

 
991

Normal  Cooling (b)
663

 
660

 
946

 
940

 
 
 
 
 
 
 
 
Western Region
 

 
 

 
 

 
 

Actual  Heating (a)

 

 
302

 
143

Normal  Heating (b)

 

 
200

 
205

 
 
 
 
 
 
 
 
Actual  Cooling (d)
1,367

 
1,387

 
2,309

 
2,464

Normal  Cooling (b)
1,346

 
1,339

 
2,358

 
2,346


(a)
Heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.
(d)
Western Region cooling degree days are calculated on a 70 degree temperature base.


22



Third Quarter of 2014 Compared to Third Quarter of 2013
Reconciliation of Third Quarter of 2013 to Third Quarter of 2014
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
 
 
 
Third Quarter of 2013
 
$
119

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
25

Transmission Revenues
 
12

Other Revenues
 
1

Total Change in Gross Margin
 
38

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(75
)
Depreciation and Amortization
 
(17
)
Taxes Other Than Income Taxes
 
1

Interest and Investment Income
 
3

Carrying Costs Income
 
3

Allowance for Equity Funds Used During Construction
 
1

Interest Expense
 
4

Total Change in Expenses and Other
 
(80
)
 
 
 

Income Tax Expense
 
15

 
 
 

Third Quarter of 2014
 
$
92


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

Retail Margins increased $25 million primarily due to the following:
A $23 million increase in TCC and TNC revenues primarily due to increased transmission investment in Texas as well as increased usage.
A $2 million increase in revenues primarily associated with Ohio rate riders/trackers and PJM revenues, partially offset by regulatory provisions. These increases have corresponding increases in expense items discussed below.
Transmission Revenues increased $12 million primarily due to increased transmission investment, increased transmission revenues from customers who have switched to alternative CRES providers and rate increases for customers in the PJM region.  This increase in transmission revenues related to CRES providers primarily offsets lost revenues included in Retail Margins above.

23



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

Other Operation and Maintenance expenses increased $75 million primarily due to the following:
A $74 million increase in expenses, including PJM expenses and the Ohio storm amortization, currently fully recovered in rate recovery riders/trackers.
A $9 million increase in employee-related expenses.
These increases were partially offset by:
A $7 million decrease in transmission expenses primarily related to PJM services.    
Depreciation and Amortization expenses increased $17 million primarily due to the following:
A $9 million increase in amortization related to TCC and OPCo securitizations, which are offset in Retail Margins above.
An $8 million increase due to an increase in the depreciable base of transmission and distribution assets.
Interest Expense decreased $4 million primarily due to reduced long-term debt outstanding.
Income Tax Expense decreased $15 million primarily due to a decrease in pretax book income.


24



Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013
Reconciliation of Nine Months Ended September 30, 2013 to Nine Months Ended September 30, 2014
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
 
 
 
Nine Months Ended September 30, 2013
 
$
281

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
172

Transmission Revenues
 
59

Other Revenues
 
10

Total Change in Gross Margin
 
241

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(203
)
Depreciation and Amortization
 
(50
)
Taxes Other Than Income Taxes
 
(17
)
Interest and Investment Income
 
8

Carrying Costs Income
 
10

Allowance for Equity Funds Used During Construction
 
4

Interest Expense
 
9

Total Change in Expenses and Other
 
(239
)
 
 
 

Income Tax Expense
 
(4
)
 
 
 

Nine Months Ended September 30, 2014
 
$
279


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

Retail Margins increased $172 million primarily due to the following:
A $101 million increase in revenues primarily associated with Ohio rate riders/trackers and PJM revenues, partially offset by regulatory provisions. These increases have corresponding increases in expense items discussed below.
A $71 million increase in TCC and TNC revenues primarily due to increased transmission investment in Texas as well as increased usage.
Transmission Revenues increased $59 million primarily due to increased transmission investment, increased transmission revenues from customers who have switched to alternative CRES providers and rate increases for customers in the PJM region.  This increase in transmission revenues related to CRES providers primarily offsets lost revenues included in Retail Margins above.
Other Revenues increased $10 million primarily due to an increase in Texas securitization revenues which is offset in Depreciation and Amortization below. This increase is also partially offset by a $4 million demand side management bonus recorded in 2013.


25



Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $203 million primarily due to the following:
A $150 million increase in recoverable expenses, including PJM expenses and the Ohio storm amortization, currently fully recovered in rate recovery riders/trackers.
A $19 million increase in expenses related to various distribution services and vegetation management.
A $14 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 has corresponding increases in Retail Margins above.
An $11 million increase in employee-related expenses.
A $7 million increase in storm-related expenses primarily in OPCo's service territory.
Depreciation and Amortization expenses increased $50 million primarily due to the following:
A $32 million increase in amortization related to TCC and OPCo securitizations, which are offset in Retail Margins.
An $18 million increase due to an increase in the depreciable base of transmission and distribution assets.
Taxes Other Than Income Taxes increased $17 million primarily due to increased property taxes.
Interest and Investment Income increased $8 million primarily due to interest on affiliated notes resulting from corporate separation.
Carrying Costs Income increased $10 million primarily due to increased capacity deferral carrying charges.
Interest Expense decreased $9 million primarily due to reduced long-term debt outstanding.

26



AEP TRANSMISSION HOLDCO

Third Quarter of 2014 Compared to Third Quarter of 2013

Earnings Attributable to AEP Common Shareholders from our AEP Transmission Holdco segment increased from $22 million in 2013 to $43 million in 2014 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

Earnings Attributable to AEP Common Shareholders from our AEP Transmission Holdco segment increased from $53 million in 2013 to $114 million in 2014 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT. During this period, net plant increased from $1.3 billion to $2.4 billion.

GENERATION & MARKETING
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Generation & Marketing
 
2014
 
2013
 
2014
 
2013
 
 
(in millions)
Revenues
 
$
901

 
$
1,001

 
$
3,065

 
$
2,813

Fuel, Purchased Electricity and Other
 
529

 
648

 
1,894

 
1,764

Gross Margin
 
372

 
353

 
1,171

 
1,049

Other Operation and Maintenance
 
122

 
106

 
363

 
342

Asset Impairments and Other Related Charges
 

 

 

 
154

Depreciation and Amortization
 
56

 
57

 
169

 
180

Taxes Other Than Income Taxes
 
12

 
11

 
37

 
44

Operating Income
 
182

 
179

 
602

 
329

Interest and Investment Income
 
2

 

 
4

 
2

Interest Expense
 
(12
)
 
(10
)
 
(35
)
 
(44
)
Income Before Income Tax Expense
 
172

 
169

 
571

 
287

Income Tax Expense
 
55

 
57

 
193

 
99

Net Income
 
117

 
112

 
378

 
188

Net Income Attributable to Noncontrolling Interests
 

 

 

 

Earnings Attributable to AEP Common Shareholders
 
$
117

 
$
112

 
$
378

 
$
188


Summary of MWhs Generated for Generation & Marketing
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions of MWhs)
Fuel Type:
 

 
 

 
 

 
 

Coal
16

 
10

 
37

 
29

Natural Gas
2

 
2

 
6

 
5

Total MWhs
18

 
12

 
43

 
34



27



Third Quarter of 2014 Compared to Third Quarter of 2013
Reconciliation of Third Quarter of 2013 to Third Quarter of 2014
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
 
 
 
Third Quarter of 2013
 
$
112

 
 
 

Changes in Gross Margin:
 
 

Generation
 
19

Total Change in Gross Margin
 
19

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(16
)
Depreciation and Amortization
 
1

Taxes Other Than Income Taxes
 
(1
)
Interest and Investment Income
 
2

Interest Expense
 
(2
)
Total Change in Expenses and Other
 
(16
)
 
 
 

Income Tax Expense
 
2

 
 
 

Third Quarter of 2014
 
$
117


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:

Gross Margin increased $19 million primarily due to lower fuel expenses.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $16 million primarily due to an increase in plant maintenance.

28



Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013
Reconciliation of Nine Months Ended September 30, 2013 to Nine Months Ended September 30, 2014
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
 
 
 
Nine Months Ended September 30, 2013
 
$
188

 
 
 

Changes in Gross Margin:
 
 

Generation
 
118

Retail, Trading and Marketing
 
4

Total Change in Gross Margin
 
122

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(21
)
Asset Impairments and Other Related Charges
 
154

Depreciation and Amortization
 
11

Taxes Other Than Income Taxes
 
7

Interest and Investment Income
 
2

Interest Expense
 
9

Total Change in Expenses and Other
 
162

 
 
 

Income Tax Expense
 
(94
)
 
 
 

Nine Months Ended September 30, 2014
 
$
378


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

Generation increased $118 million primarily due to increased demand and market prices driven by cold temperatures in the first quarter of 2014.

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

Other Operation and Maintenance expenses increased $21 million primarily due to increased plant maintenance.
Asset Impairments and Other Related Charges decreased by $154 million primarily due to the 2013 impairment of Muskingum River Plant, Unit 5.
Depreciation and Amortization expenses decreased $11 million primarily due to the 2013 impairment of Muskingum River Plant, Unit 5.
Taxes Other Than Income Taxes decreased $7 million primarily due to a decrease in property taxes related to the 2012 and 2013 plant impairments.
Interest Expense decreased $9 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
Income Tax Expense increased $94 million primarily due to an increase in pretax book income.


29



AEP RIVER OPERATIONS

Third Quarter of 2014 Compared to Third Quarter of 2013

Earnings Attributable to AEP Common Shareholders from our AEP River Operations segment increased from a loss of $1 million in 2013 to income of $11 million in 2014 due to a 20% increase in barge freight revenue for the third quarter of 2014 compared to the third quarter of 2013. The increase in freight revenue is primarily due to improvements in barge freight demand.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

Earnings Attributable to AEP Common Shareholders from our AEP River Operations segment increased from a loss of $12 million in 2013 to income of $17 million in 2014 due to a 30% increase in barge freight revenue for 2014 compared to 2013. The additional revenue resulted from improvements in river conditions and increased barge freight demand.

CORPORATE AND OTHER

Third Quarter of 2014 Compared to Third Quarter of 2013

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from $8 million in 2013 to $11 million in 2014 primarily due to the recording of federal and state income tax adjustments in the third quarter of 2014.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from $119 million in 2013 to $4 million in 2014 primarily due to a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.

AEP SYSTEM INCOME TAXES

Third Quarter of 2014 Compared to Third Quarter of 2013

Income Tax Expense increased $12 million primarily due to an increase in pretax book income, partially offset by the recording of federal and state income tax adjustments in the third quarter of 2014.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

Income Tax Expense increased $271 million primarily due to an increase in pretax book income and by a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.


30



FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization
 
September 30, 2014
 
December 31, 2013
 
(dollars in millions)
Long-term Debt, including amounts due within one year
$
18,058

 
49.9
%
 
$
18,377

 
52.2
%
Short-term Debt
1,282

 
3.5

 
757

 
2.1

Total Debt
19,340

 
53.4

 
19,134

 
54.3

AEP Common Equity
16,868

 
46.6

 
16,085

 
45.7

Noncontrolling Interests
4

 

 
1

 

 
 
 
 
 
 
 
 
Total Debt and Equity Capitalization
$
36,212

 
100.0
%
 
$
35,220

 
100.0
%

Our ratio of debt-to-total capital improved from 54.3% as of December 31, 2013 to 53.4% as of September 30, 2014 primarily due to an increase in our common equity from earnings.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability.  We believe we have adequate liquidity under our existing credit facilities.  As of September 30, 2014, we had $3.5 billion in aggregate credit facility commitments to support our operations.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  We are committed to maintaining adequate liquidity.  We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, sale-and-leaseback or leasing agreements or common stock.

Commercial Paper Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  As of September 30, 2014, our available liquidity was approximately $3.1 billion as illustrated in the table below:
 
 
Amount
 
Maturity
 
 
(in millions)
 
 
Commercial Paper Backup:
 

 
 
 
Revolving Credit Facility
$
1,750

 
June 2016
 
Revolving Credit Facility
1,750

 
July 2017
Total
3,500

 
 
Cash and Cash Equivalents
194

 
 
Total Liquidity Sources
3,694

 
 
Less:
AEP Commercial Paper Outstanding
532

 
 
 
Letters of Credit Issued
76

 
 
 
 
 
 
 
Net Available Liquidity
$
3,086

 
 

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

31



debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  The maximum amount of commercial paper outstanding during the first nine months of 2014 was $877 million.  The weighted-average interest rate for our commercial paper during 2014 was 0.26%.

Other Credit Facilities

In January 2014, we issued letters of credit under an $85 million uncommitted facility signed in October 2013. As of September 30, 2014, the maximum future payment for letters of credit issued under the uncommitted facility was $78 million with maturity dates through January 2015. An uncommitted facility gives the issuer of the facility the right to accept or decline each request we make under the facility.

Securitized Accounts Receivable

Our receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased from $700 million and expires in June 2016.

Debt Covenants and Borrowing Limitations

Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually defined in our credit agreements. Debt as defined in the revolving credit agreements excludes securitization bonds and debt of AEP Credit. As of September 30, 2014, this contractually-defined percentage was 49.9%. Nonperformance under these covenants could result in an event of default under these credit agreements. As of September 30, 2014, we complied with all of the covenants contained in these credit agreements. In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements. This condition also applies in a majority of our non-exchange traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable. However, a default under our non-exchange traded commodity contracts does not cause an event of default under our credit agreements.

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

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

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.53 per share in October 2014. Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Our income primarily derives from our common stock equity in the earnings of our utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

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

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.

32




CASH FLOW

Managing our cash flows is a major factor in maintaining our liquidity strength.
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
(in millions)
Cash and Cash Equivalents at Beginning of Period
$
118

 
$
279

Net Cash Flows from Operating Activities
3,725

 
3,040

Net Cash Flows Used for Investing Activities
(3,081
)
 
(2,520
)
Net Cash Flows Used for Financing Activities
(568
)
 
(652
)
Net Increase (Decrease) in Cash and Cash Equivalents
76

 
(132
)
Cash and Cash Equivalents at End of Period
$
194

 
$
147


Cash from operations and short-term borrowings provides working capital and allows us to meet other short-term cash needs.
 
Operating Activities
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
(in millions)
Net Income
$
1,446

 
$
1,137

Depreciation and Amortization
1,441

 
1,310

Other
838

 
593

Net Cash Flows from Operating Activities
$
3,725

 
$
3,040


Net Cash Flows from Operating Activities were $3.7 billion in 2014 consisting primarily of Net Income of $1.4 billion and $1.4 billion of noncash Depreciation and Amortization partially offset by $106 million of Ohio capacity deferrals as a result of the PUCO's July 2012 approval of a capacity deferral mechanism. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. Deferred Income Taxes increased primarily due to provisions in the Taxpayer Relief Act of 2012 and an increase in tax/book temporary differences from operations. The reduction in Fuel, Material and Supplies balances reflects a decrease in fuel inventory due to the cold winter weather and increased generation.

Net Cash Flows from Operating Activities were $3 billion in 2013 consisting primarily of Net Income of $1.1 billion, and $1.3 billion of noncash Depreciation and Amortization and $298 million of Asset Impairments related to Muskingum River Plant, Unit 5, Turk and Big Sandy Plants, partially offset by $157 million of Ohio capacity deferrals as a result of the PUCO's July 2012 approval of a capacity deferral mechanism. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. Deferred Income Taxes increased primarily due to provisions in the Taxpayer Relief Act of 2012 and an increase in tax/book temporary differences from operations. Net cash flows for Accrued Taxes were a result of recording the estimated federal tax loss associated with tax/book temporary differences and the recognition of the tax benefit related to the U.K. Windfall Tax.


33



Investing Activities
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
(in millions)
Construction Expenditures
$
(2,899
)
 
$
(2,481
)
Acquisitions of Nuclear Fuel
(109
)
 
(110
)
Acquisitions of Assets/Businesses
(45
)
 
(6
)
Insurance Proceeds Related to Cook Plant Fire

 
72

Proceeds from Sales of Assets
2

 
14

Other
(30
)
 
(9
)
Net Cash Flows Used for Investing Activities
$
(3,081
)
 
$
(2,520
)

Net Cash Flows Used for Investing Activities were $3.1 billion in 2014 primarily due to Construction Expenditures for environmental, distribution and transmission investments. We also purchased transmission assets for $38 million.

Net Cash Flows Used for Investing Activities were $2.5 billion in 2013 primarily due to Construction Expenditures for environmental, distribution and transmission investments.

Financing Activities
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
(in millions)
Issuance of Common Stock, Net
$
63

 
$
61

Issuance of Debt, Net
193

 
43

Dividends Paid on Common Stock
(736
)
 
(709
)
Other
(88
)
 
(47
)
Net Cash Flows Used for Financing Activities
$
(568
)
 
$
(652
)

Net Cash Flows Used for Financing Activities in 2014 were $568 million. Our net debt issuances were $193 million. The net issuances included issuances of $650 million of senior unsecured notes, $343 million of pollution control bonds and $224 million of other debt notes and an increase in short-term borrowing of $525 million offset by retirements of $953 million of senior unsecured and other debt notes, $312 million of pollution control bonds and $273 million of securitization bonds. We paid common stock dividends of $736 million. See Note 12 - Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows Used for Financing Activities in 2013 were $652 million. Our net debt issuances were $43 million. The net issuances included issuances of $475 million of senior unsecured notes, $800 million draws on a $1 billion term credit facility, $305 million of pollution control bonds, $267 million of securitization bonds, $251 million of notes payable and other debt and an increase in short-term borrowing of $237 million offset by retirements of $1.8 billion of senior unsecured and other debt notes, $211 million of securitization bonds and $281 million of pollution control bonds. We paid common stock dividends of $709 million.

In October 2014, APCo remarketed $100 million of Pollution Control Bonds due in 2018 at 1.625%.

In October 2014, I&M retired $5 million of Notes Payable related to DCC Fuel.

BUDGETED CONSTRUCTION EXPENDITURES

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

34




OFF-BALANCE SHEET ARRANGEMENTS

Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that we enter in the normal course of business.  The following identifies significant off-balance sheet arrangements:
 
September 30,
2014
 
December 31,
2013
 
(in millions)
Rockport Plant, Unit 2 Future Minimum Lease Payments
$
1,256

 
$
1,330

Railcars Maximum Potential Loss from Lease Agreement
19

 
19


For complete information on each of these off-balance sheet arrangements, see the “Off-balance Sheet Arrangements” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2013 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2013 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2013 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

ACCOUNTING PRONOUNCEMENTS

Pronouncements Effective in the Future

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

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

35




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

Our Transmission and Distribution Utilities segment is exposed to FTR price risk as it relates to congestion during the June 2012 - May 2015 Ohio ESP period. Additional risk includes interest rate risk.

Our Generation & Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM and MISO. This segment is exposed to certain market risks as a marketer of wholesale and retail electricity. These risks include commodity price risk, interest rate risk and credit risk. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates. In addition, our Generation & Marketing segment is also exposed to certain market risks as a major power producer and through its transactions in wholesale electricity, natural gas and coal trading and marketing contracts.

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


36



The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2013:
MTM Risk Management Contract Net Assets (Liabilities)
Nine Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
Vertically
Integrated
Utilities
 
Transmission
and
Distribution
Utilities
 
Generation
&
Marketing
 
Total
 
(in millions)
Total MTM Derivative Contract Net Assets as of December 31, 2013
$
32

 
$
3

 
$
157

 
$
192

Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period
(7
)
 
(3
)
 
(32
)
 
(42
)
Fair Value of New Contracts at Inception When Entered During the Period (a)

 

 
9

 
9

Changes in Fair Value Due to Market Fluctuations During the Period (b)

 

 
21

 
21

Changes in Fair Value Allocated to Regulated Jurisdictions (c)
12

 
8

 

 
20

Total MTM Derivative Contract Net Assets as of September 30, 2014
$
37

 
$
8

 
$
155

 
$
200

Commodity Cash Flow Hedge Contracts
 
 
 

 
 

 
6

Interest Rate and Foreign Currency Cash Flow Hedge Contracts
 
 
 

 
 

 
(1
)
Fair Value Hedge Contracts
 
 
 

 
 

 
(8
)
Collateral Deposits
 
 
 

 
 

 
(14
)
Total MTM Derivative Contract Net Assets as of September 30, 2014
 
 
 

 
 

 
$
183


(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 9 – Derivatives and Hedging and Note 10 – Fair Value Measurements for additional information related to our risk management contracts.  The following tables and discussion provide information on our credit risk and market volatility risk.

Credit Risk

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


37



We have risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. As of September 30, 2014, our credit exposure net of collateral to sub investment grade counterparties was approximately 9.3%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss). As of September 30, 2014, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:
Counterparty Credit Quality
 
Exposure
Before
Credit
Collateral
 
Credit
Collateral
 
Net
Exposure
 
Number of
Counterparties
>10% of
Net Exposure
 
Net Exposure
of
Counterparties
>10%
 
 
(in millions, except number of counterparties)
Investment Grade
 
$
482

 
$
1

 
$
481

 
2

 
$
245

Split Rating
 
14

 

 
14

 
1

 
13

Noninvestment Grade
 
2

 
1

 
1

 
2

 
1

No External Ratings:
 
 

 
 

 


 
 

 
 

Internal Investment Grade
 
71

 

 
71

 
4

 
44

Internal Noninvestment Grade
 
71

 
14

 
57

 
1

 
29

Total as of September 30, 2014
 
$
640

 
$
16

 
$
624

 
10

 
$
332

 
 
 
 
 
 
 
 
 
 
 
Total as of December 31, 2013
 
$
787

 
$
18

 
$
769

 
9

 
$
381


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

Value at Risk (VaR) Associated with Risk Management Contracts

We use a risk measurement model, which calculates VaR, to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of September 30, 2014, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

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

VaR Model
Nine Months Ended
 
Twelve Months Ended
September 30, 2014
 
December 31, 2013
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
(in millions)
 
(in millions)
$

 
$
3

 
$
1

 
$

 
$

 
$
1

 
$

 
$


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

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

38




Interest Rate Risk

We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which our interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. As calculated on debt outstanding as of September 30, 2014 and December 31, 2013, the estimated EaR on our debt portfolio for the following twelve months was $42 million and $32 million, respectively.

39




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2014 and 2013
(in millions, except per-share and share amounts)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
REVENUES
 
 
 
 
 
 
 
 
Vertically Integrated Utilities
 
$
2,432

 
$
2,543

 
$
7,217

 
$
7,075

Transmission and Distribution Utilities
 
1,163

 
1,139

 
3,388

 
3,248

Generation & Marketing
 
538

 
359

 
1,932

 
915

Other Revenues
 
169

 
135

 
457

 
346

TOTAL REVENUES
 
4,302

 
4,176

 
12,994

 
11,584

 
 
 
 
 
 
 
 
 
EXPENSES
 
 

 
 

 
 

 
 

Fuel and Other Consumables Used for Electric Generation
 
1,080

 
1,168

 
3,291

 
3,107

Purchased Electricity for Resale
 
449

 
373

 
1,560

 
1,103

Other Operation
 
787

 
677

 
2,327

 
2,079

Maintenance
 
321

 
261

 
953

 
839

Asset Impairments and Other Related Charges
 

 
144

 

 
298

Depreciation and Amortization
 
507

 
447

 
1,441

 
1,310

Taxes Other Than Income Taxes
 
233

 
231

 
689

 
671

TOTAL EXPENSES
 
3,377

 
3,301

 
10,261

 
9,407

 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
925

 
875

 
2,733

 
2,177

 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 

 
 

 
 

 
 

Interest and Investment Income
 
1

 
3

 
5

 
55

Carrying Costs Income
 
7

 
8

 
22

 
20

Allowance for Equity Funds Used During Construction
 
27

 
19

 
74

 
51

Interest Expense
 
(221
)
 
(225
)
 
(662
)
 
(685
)
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
 
739

 
680

 
2,172

 
1,618

 
 
 
 
 
 
 
 
 
Income Tax Expense
 
269

 
257

 
791

 
520

Equity Earnings of Unconsolidated Subsidiaries
 
24

 
11

 
65

 
39

 
 
 
 
 
 
 
 
 
NET INCOME
 
494

 
434

 
1,446

 
1,137

 
 
 
 
 
 
 
 
 
Net Income Attributable to Noncontrolling Interests
 
1

 
1

 
3

 
3

 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
493

 
$
433

 
$
1,443

 
$
1,134

 
 
 
 
 
 
 
 
 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
 
488,912,892

 
486,932,747

 
488,361,017

 
486,353,876

 
 
 
 
 
 
 
 
 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
1.01

 
$
0.89

 
$
2.95

 
$
2.33

 
 
 
 
 
 
 
 
 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
 
488,970,647

 
487,258,905

 
488,597,178

 
486,792,914

 
 
 
 
 
 
 
 
 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
1.01

 
$
0.89

 
$
2.95

 
$
2.33

 
 
 
 
 
 
 
 
 
CASH DIVIDENDS DECLARED PER SHARE
 
$
0.50

 
$
0.49

 
$
1.50

 
$
1.45

 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 46.


40



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2014 and 2013
(in millions)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
Net Income
 
$
494

 
$
434

 
$
1,446

 
$
1,137

 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
 
 

 
 

 
 

 
 

Cash Flow Hedges, Net of Tax of $1 and $1 for the Three Months Ended
September 30, 2014 and 2013, Respectively, and $3 and $7 for the Nine
Months Ended September 30, 2014 and 2013, Respectively
 
(2
)
 
(1
)
 
6

 
13

Securities Available for Sale, Net of Tax of $0 and $0 for the Three Months
Ended September 30, 2014 and 2013, Respectively, and $0 and $1 for the
Nine Months Ended September 30, 2014 and 2013, Respectively
 

 
1

 
1

 
2

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1
and $4 for the Three Months Ended September 30, 2014 and 2013,
Respectively, and $2 and $9 for the Nine Months Ended September 30,
2014 and 2013, Respectively
 
1

 
7

 
3

 
16

 
 
 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
 
(1
)
 
7

 
10

 
31

 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
493

 
441

 
1,456

 
1,168

 
 
 
 
 
 
 
 
 
Total Comprehensive Income Attributable to Noncontrolling Interests
 
1

 
1

 
3

 
3

 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
COMMON SHAREHOLDERS
 
$
492

 
$
440

 
$
1,453

 
$
1,165

 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 46.


41



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 2014 and 2013
(in millions)
(Unaudited)
 
AEP Common Shareholders
 
 
 
 
 
Common Stock
 
 
 
 
 
Accumulated
Other
Comprehensive
Income (Loss)
 
 
 
 
 
Shares
 
Amount
 
Paid-in
Capital
 
Retained
Earnings
 
 
Noncontrolling
Interests
 
Total
TOTAL EQUITY - DECEMBER 31, 2012
506

 
$
3,289

 
$
6,049

 
$
6,236

 
$
(337
)
 
$

 
$
15,237

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Common Stock
2

 
10

 
51

 
 

 
 

 
 

 
61

Common Stock Dividends
 

 
 

 
 

 
(706
)
 
 

 
(3
)
 
(709
)
Other Changes in Equity
 

 
 

 
5

 
 

 
 

 
1

 
6

Net Income
 
 
 
 
 
 
1,134

 
 

 
3

 
1,137

Other Comprehensive Income
 

 
 

 
 

 
 

 
31

 
 

 
31

TOTAL EQUITY - SEPTEMBER 30, 2013
508

 
$
3,299

 
$
6,105

 
$
6,664

 
$
(306
)
 
$
1

 
$
15,763

 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY - DECEMBER 31, 2013
508

 
$
3,303

 
$
6,131

 
$
6,766

 
$
(115
)
 
$
1

 
$
16,086

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Common Stock
2

 
9

 
54

 
 

 
 

 
 

 
63

Common Stock Dividends
 

 
 

 
 

 
(733
)
 
 

 
(3
)
 
(736
)
Other Changes in Equity
 

 
 

 
6

 
(6
)
 
 

 
3

 
3

Net Income
 
 
 
 
 
 
1,443

 
 

 
3

 
1,446

Other Comprehensive Income
 

 
 

 
 

 
 

 
10

 
 

 
10

TOTAL EQUITY - SEPTEMBER 30, 2014
510

 
$
3,312

 
$
6,191

 
$
7,470

 
$
(105
)
 
$
4

 
$
16,872

 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 46.



42



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2014 and December 31, 2013
(in millions)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2014
 
2013
CURRENT ASSETS
 
 

 
 

Cash and Cash Equivalents
 
$
194

 
$
118

Other Temporary Investments
(September 30, 2014 and December 31, 2013 Amounts Include $304 and $335, Respectively, Related to Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and EIS)
 
318

 
353

Accounts Receivable:
 
 

 
 

Customers
 
671

 
746

Accrued Unbilled Revenues
 
107

 
157

Pledged Accounts Receivable – AEP Credit
 
1,013

 
945

Miscellaneous
 
83

 
72

Allowance for Uncollectible Accounts
 
(19
)
 
(60
)
Total Accounts Receivable
 
1,855

 
1,860

Fuel
 
472

 
701

Materials and Supplies
 
733

 
722

Risk Management Assets
 
135

 
160

Regulatory Asset for Under-Recovered Fuel Costs
 
145

 
80

Margin Deposits
 
82

 
70

Prepayments and Other Current Assets
 
177

 
246

TOTAL CURRENT ASSETS
 
4,111

 
4,310

 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 

 
 

Electric:
 
 

 
 

Generation
 
25,565

 
25,074

Transmission
 
11,649

 
10,893

Distribution
 
16,938

 
16,377

Other Property, Plant and Equipment (Including Plant to be Retired, Coal Mining and Nuclear Fuel)
 
5,688

 
5,470

Construction Work in Progress
 
3,283

 
2,471

Total Property, Plant and Equipment
 
63,123

 
60,285

Accumulated Depreciation and Amortization
 
20,059

 
19,288

TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
43,064

 
40,997

 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 

 
 

Regulatory Assets
 
4,308

 
4,376

Securitized Assets
 
2,159

 
2,373

Spent Nuclear Fuel and Decommissioning Trusts
 
2,020

 
1,932

Goodwill
 
91

 
91

Long-term Risk Management Assets
 
228

 
297

Deferred Charges and Other Noncurrent Assets
 
1,944

 
2,038

TOTAL OTHER NONCURRENT ASSETS
 
10,750

 
11,107

 
 
 
 
 
TOTAL ASSETS
 
$
57,925

 
$
56,414

 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 46.


43



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2014 and December 31, 2013
(dollars in millions)
(Unaudited)
 
 
 
 
 
 
 
September 30,
 
December 31,
 
 
 
 
 
 
 
2014
 
2013
CURRENT LIABILITIES
 
 
 
 
Accounts Payable
 
 
 
 
 
 
$
1,259

 
$
1,266

Short-term Debt:
 
 
 
 
 
 
 
 
 
Securitized Debt for Receivables – AEP Credit
 
 
 
 
750

 
700

Other Short-term Debt
 
 
 
 
 
 
532

 
57

Total Short-term Debt
 
 
 
 
 
 
1,282

 
757

Long-term Debt Due Within One Year
(September 30, 2014 and December 31, 2013 Amounts Include $409 and $416, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine)
 
 
2,381

 
1,549

Risk Management Liabilities
 
 
 
 
 
 
60

 
90

Customer Deposits
 
 
 
 
 
 
315

 
299

Accrued Taxes
 
 
 
 
 
 
769

 
822

Accrued Interest
 
 
 
 
 
 
219

 
245

Regulatory Liability for Over-Recovered Fuel Costs
 
 
 
 
53

 
119

Other Current Liabilities
 
 
 
 
 
 
1,119

 
965

TOTAL CURRENT LIABILITIES
 
 
 
 
 
 
7,457

 
6,112

 
 
 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
Long-term Debt
 
 
 
 
 
 
 
 
 
(September 30, 2014 and December 31, 2013 Amounts Include $2,230 and $2,532, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy and Sabine)
 
 
15,677

 
16,828

Long-term Risk Management Liabilities
 
 
 
 
 
 
120

 
177

Deferred Income Taxes
 
 
 
 
 
 
10,506

 
10,300

Regulatory Liabilities and Deferred Investment Tax Credits
 
 
3,837

 
3,694

Asset Retirement Obligations
 
 
 
 
 
 
1,923

 
1,835

Employee Benefits and Pension Obligations
 
 
 
 
 
 
414

 
415

Deferred Credits and Other Noncurrent Liabilities
 
 
1,119

 
967

TOTAL NONCURRENT LIABILITIES
 
 
 
 
 
 
33,596

 
34,216

 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 
 
 
 
41,053

 
40,328

 
 
 
 
 
 
 
 
 
 
Rate Matters (Note 4)
 
 
 
 
 
 

 

Commitments and Contingencies (Note 5)
 
 
 
 
 
 

 

 
 
 
 
 
 
 
 
 
 
EQUITY
 
 
 
 
Common Stock – Par Value – $6.50 Per Share:
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
 
 
 
 
Shares Authorized
 
600,000,000
 
600,000,000
 
 
 
 
 
Shares Issued
 
509,563,446
 
508,113,964
 
 
 
 
 
(20,336,592 Shares were Held in Treasury as of September 30, 2014 and December 31, 2013)
 
 
3,312

 
3,303

Paid-in Capital
 
 
 
 
 
 
6,191

 
6,131

Retained Earnings
 
 
 
 
 
 
7,470

 
6,766

Accumulated Other Comprehensive Income (Loss)
 
 
(105
)
 
(115
)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY
 
 
16,868

 
16,085

 
 
 
 
 
 
 
 
 
 
Noncontrolling Interests
 
 
 
 
 
 
4

 
1

 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY
 
 
 
 
 
 
16,872

 
16,086

 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 
 
 
 
 
 
$
57,925

 
$
56,414

 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 46.

44



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2014 and 2013
(in millions)
(Unaudited)
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
OPERATING ACTIVITIES
 
 

 
 

Net Income
 
$
1,446

 
$
1,137

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
 
Depreciation and Amortization
 
1,441

 
1,310

Deferred Income Taxes
 
383

 
582

Asset Impairments and Other Related Charges
 

 
298

Carrying Costs Income
 
(22
)
 
(20
)
Allowance for Equity Funds Used During Construction
 
(74
)
 
(51
)
Mark-to-Market of Risk Management Contracts
 
15

 
29

Amortization of Nuclear Fuel
 
114

 
101

Pension Contributions to Qualified Plan Trust
 
(71
)
 

Property Taxes
 
220

 
191

Fuel Over/Under-Recovery, Net
 
(77
)
 
38

Deferral of Ohio Capacity Costs, Net
 
(106
)
 
(157
)
Change in Other Noncurrent Assets
 
(54
)
 
(35
)
Change in Other Noncurrent Liabilities
 
272

 
16

Changes in Certain Components of Working Capital:
 
 
 
 
Accounts Receivable, Net
 

 
4

Fuel, Materials and Supplies
 
222

 
72

Accounts Payable
 
(43
)
 
(28
)
Accrued Taxes, Net
 
32

 
(278
)
Other Current Assets
 
(12
)
 
(5
)
Other Current Liabilities
 
39

 
(164
)
Net Cash Flows from Operating Activities
 
3,725

 
3,040

 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
Construction Expenditures
 
(2,899
)
 
(2,481
)
Change in Other Temporary Investments, Net
 
37

 
53

Purchases of Investment Securities
 
(791
)
 
(693
)
Sales of Investment Securities
 
746

 
635

Acquisitions of Nuclear Fuel
 
(109
)
 
(110
)
Acquisitions of Assets/Businesses
 
(45
)
 
(6
)
Insurance Proceeds Related to Cook Plant Fire
 

 
72

Proceeds from Sales of Assets
 
2

 
14

Other Investing Activities
 
(22
)
 
(4
)
Net Cash Flows Used for Investing Activities
 
(3,081
)
 
(2,520
)
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
Issuance of Common Stock, Net
 
63

 
61

Issuance of Long-term Debt
 
1,206

 
2,087

Commercial Paper and Credit Facility Borrowings
 

 
17

Change in Short-term Debt, Net
 
525

 
240

Retirement of Long-term Debt
 
(1,538
)
 
(2,281
)
Commercial Paper and Credit Facility Repayments
 

 
(20
)
Principal Payments for Capital Lease Obligations
 
(91
)
 
(53
)
Dividends Paid on Common Stock
 
(736
)
 
(709
)
Other Financing Activities
 
3

 
6

Net Cash Flows Used for Financing Activities
 
(568
)
 
(652
)
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
76

 
(132
)
Cash and Cash Equivalents at Beginning of Period
 
118

 
279

Cash and Cash Equivalents at End of Period
 
$
194

 
$
147

 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
649

 
$
702

Net Cash Paid (Received) for Income Taxes
 
109

 
(64
)
Noncash Acquisitions Under Capital Leases
 
80

 
53

Construction Expenditures Included in Current Liabilities as of September 30,
 
515

 
363

 
 
 
 
 
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 46.


45



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Page
Number
 
 
Significant Accounting Matters
New Accounting Pronouncements
Comprehensive Income
Rate Matters
Commitments, Guarantees and Contingencies
Impairments
Benefit Plans
Business Segments
Derivatives and Hedging
Fair Value Measurements
Income Taxes
Financing Activities
Variable Interest Entities


46



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

1.  SIGNIFICANT ACCOUNTING MATTERS

General

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

In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods.  Net income for the three and nine months ended September 30, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014.  The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2013 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 25, 2014.

Revenue Recognition
    
Electricity Supply and Delivery Activities - Transactions with PJM

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

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

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

SPP Integrated Power Market

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


47



Earnings Per Share (EPS)

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

The following tables present our basic and diluted EPS calculations included on our condensed statements of income:
 
Three Months Ended September 30,
 
2014
 
2013
 
(in millions, except per share data)
 
 

 
$/share
 
 
 
$/share
Earnings Attributable to AEP Common Shareholders
$
493

 
 

 
$
433

 
 

 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares Outstanding
488.9

 
$
1.01

 
486.9

 
$
0.89

Weighted Average Dilutive Effect of Restricted Stock Units
0.1

 

 
0.4

 

Weighted Average Number of Diluted Shares Outstanding
489.0

 
$
1.01

 
487.3

 
$
0.89


 
Nine Months Ended September 30,
 
2014
 
2013
 
(in millions, except per share data)
 
 

 
$/share
 
 
 
$/share
Earnings Attributable to AEP Common Shareholders
$
1,443

 
 
 
$
1,134

 
 
 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares Outstanding
488.4

 
$
2.95

 
486.4

 
$
2.33

Weighted Average Dilutive Effect of Restricted Stock Units
0.2

 

 
0.4

 

Weighted Average Number of Diluted Shares Outstanding
488.6

 
$
2.95

 
486.8

 
$
2.33


There were no antidilutive shares outstanding as of September 30, 2014 and 2013.


48



2. NEW ACCOUNTING PRONOUNCEMENTS

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

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

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

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014 with early adoption permitted. If applicable, this standard will change the presentation of our financial statements but will not affect the calculation of net income, comprehensive income or earnings per share.

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

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

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


49



3.  COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2014 and 2013.  All amounts in the following tables are presented net of related income taxes.

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2014
 
Cash Flow Hedges
 
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Securities
Available for Sale
 
Pension
and OPEB
 
Total
 
(in millions)
Balance in AOCI as of June 30, 2014
$
6

 
$
(21
)
 
$
8

 
$
(97
)
 
$
(104
)
Change in Fair Value Recognized in AOCI
3

 

 

 

 
3

Amounts Reclassified from AOCI
(6
)
 
1

 

 
1

 
(4
)
Net Current Period Other
Comprehensive Income
(3
)
 
1

 

 
1

 
(1
)
Balance in AOCI as of September 30, 2014
$
3

 
$
(20
)
 
$
8

 
$
(96
)
 
$
(105
)

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2013
 
Cash Flow Hedges
 
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Securities
Available for Sale
 
Pension
and OPEB
 
Total
 
(in millions)
Balance in AOCI as of June 30, 2013
$
1

 
$
(25
)
 
$
5

 
$
(294
)
 
$
(313
)
Change in Fair Value Recognized in AOCI
1

 

 
1

 

 
2

Amounts Reclassified from AOCI
(3
)
 
1

 

 
7

 
5

Net Current Period Other
Comprehensive Income
(2
)
 
1

 
1

 
7

 
7

Balance in AOCI as of September 30, 2013
$
(1
)
 
$
(24
)
 
$
6

 
$
(287
)
 
$
(306
)

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2014
 
Cash Flow Hedges
 
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Securities
Available for Sale
 
Pension
and OPEB
 
Total
 
(in millions)
Balance in AOCI as of December 31, 2013
$

 
$
(23
)
 
$
7

 
$
(99
)
 
$
(115
)
Change in Fair Value Recognized in AOCI
(8
)
 

 
1

 

 
(7
)
Amounts Reclassified from AOCI
11

 
3

 

 
3

 
17

Net Current Period Other
Comprehensive Income
3

 
3

 
1

 
3

 
10

Balance in AOCI as of September 30, 2014
$
3

 
$
(20
)
 
$
8

 
$
(96
)
 
$
(105
)


50



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

 
$
(303
)
 
$
(337
)
Change in Fair Value Recognized in AOCI
11

 
2

 
2

 

 
15

Amounts Reclassified from AOCI
(4
)
 
4

 

 
16

 
16

Net Current Period Other
Comprehensive Income
7

 
6

 
2

 
16

 
31

Balance in AOCI as of September 30, 2013
$
(1
)
 
$
(24
)
 
$
6

 
$
(287
)
 
$
(306
)

Reclassifications from Accumulated Other Comprehensive Income

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

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2014 and 2013
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Three Months Ended September 30,
 
 
2014
 
2013
Gains and Losses on Cash Flow Hedges
 
(in millions)
Commodity:
 
 

 
 
Vertically Integrated Utilities Revenues
 
$

 
$
(1
)
Generation & Marketing Revenues
 

 
(3
)
Purchased Electricity for Resale
 
(9
)
 
(1
)
Subtotal  Commodity
 
(9
)
 
(5
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
2

 
2

Subtotal  Interest Rate and Foreign Currency
 
2

 
2

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(7
)
 
(3
)
Income Tax (Expense) Credit
 
(2
)
 
(1
)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(5
)
 
(2
)
 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 
(5
)
 
(7
)
Amortization of Actuarial (Gains)/Losses
 
7

 
18

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
2

 
11

Income Tax (Expense) Credit
 
1

 
4

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
1

 
7

 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(4
)
 
$
5



51



Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2014 and 2013
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
Gains and Losses on Cash Flow Hedges
 
(in millions)
Commodity:
 
 

 
 
Vertically Integrated Utilities Revenues
 
$

 
$
(1
)
Generation & Marketing Revenues
 

 
(8
)
Purchased Electricity for Resale
 
20

 
3

Regulatory Assets/(Liabilities), Net (a)
 
(3
)
 

Subtotal  Commodity
 
17

 
(6
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
6

 
6

Subtotal  Interest Rate and Foreign Currency
 
6

 
6

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
23

 

Income Tax (Expense) Credit
 
9

 

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
14

 

 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 
(15
)
 
(16
)
Amortization of Actuarial (Gains)/Losses
 
21

 
41

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
6

 
25

Income Tax (Expense) Credit
 
3

 
9

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
3

 
16

 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
17

 
$
16


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


52



4.  RATE MATTERS

As discussed in the 2013 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2013 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2014 and updates the 2013 Annual Report.
 
Regulatory Assets Pending Final Regulatory Approval
 
 
September 30,
 
December 31,
 
 
2014
 
2013
 Noncurrent Regulatory Assets
 
(in millions)
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
Storm Related Costs
 
$
21

 
$
22

West Virginia Vegetation Management Program
 
17

 

Ohio Economic Development Rider
 

 
14

Other Regulatory Assets Pending Final Regulatory Approval
 

 
4

Regulatory Assets Currently Not Earning a Return
 
 

 
 

Storm Related Costs
 
103

 
161

IGCC Pre-Construction Costs
 
21

 

Mountaineer Carbon Capture and Storage Product Validation Facility
 
13

 
13

Ormet Special Rate Recovery Mechanism
 
10

 
36

Expanded Net Energy Charge  Coal Inventory
 
9

 
21

Indiana Under-Recovered Capacity Costs
 

 
22

Other Regulatory Assets Pending Final Regulatory Approval
 
37

 
37

Total Regulatory Assets Pending Final Regulatory Approval
$
231

 
$
330


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

Ohio Electric Security Plan Filings

2009 – 2011 ESP

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

In October 2011, the PUCO issued an order in the remand proceeding. As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011. In February 2012, the Ohio Consumers’ Counsel (OCC) and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 - 2011 and various aspects of the approved environmental carrying charge. In February 2014, the Supreme Court of Ohio affirmed the PUCO’s decision and rejected all appeals filed by the OCC and the IEU.
 
In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin.

53



In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital rate. In November 2012, the IEU and the OCC filed appeals regarding the PUCO decision in the PIRR proceeding. These appeals principally argued that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo’s net deferred fuel balance up to the full amount. These intervenors’ appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of September 30, 2014, could reduce carrying costs by $28 million including $14 million of unrecognized equity carrying costs. As of September 30, 2014, OPCo’s net deferred fuel balance was $395 million, excluding unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending.

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

June 2012 – May 2015 ESP Including Capacity Charge

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

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and is $150/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR was collected from customers at $3.50/MWh through May 2014 and is currently collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. As of September 30, 2014, OPCo's incurred deferred capacity costs balance of $409 million, including debt carrying costs, was recorded in regulatory assets on the condensed balance sheet.

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

In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications which included the delay of the energy auctions that were originally ordered in the ESP order. As ordered, in February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. Also as ordered, in May 2014 and September 2014, OPCo conducted energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for the remaining 40% of the SSO load for delivery from January 2015 through May 2015. OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement

54



riders related to the unbundling of the FAC. In May 2014, an independent auditor was selected by the PUCO and an audit of the recovery of the fixed fuel costs began in June 2014. In October 2014, the independent auditor filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88 capacity charge, the independent auditor recommends a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and intends to oppose the findings in the audit report.

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

Proposed June 2015 - May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM capacity and energy auction-based generation through OPCo. The proposal also includes a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based purchase power agreement. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In May 2014, intervenors and the PUCO staff filed testimony that provided various recommendations including the rejection and/or modification of various riders, including the DIR and the proposed PPA. Hearings at the PUCO in the ESP case were held in June 2014. Additionally, in July 2014, OPCo submitted a separate application to continue the RSR established in the June 2012 - May 2015 ESP to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00/MWh, until the balance of the capacity deferrals has been collected. In October 2014, OPCo filed a separate application with the PUCO to propose a new PPA for inclusion in the PPA rider, discussed above. The new PPA would include an additional 2,671 MW to be purchased from AGR over the life of the respective generating units.

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

Significantly Excessive Earnings Test Filings

In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending.

In March 2014, the PUCO approved a stipulation agreement between OPCo and the PUCO staff that there were no significantly excessive earnings in 2011 for CSPCo or OPCo. In May 2014, the PUCO approved a stipulation agreement between OPCo and the PUCO staff that there were no significantly excessive earnings in 2012 for OPCo. In May 2014, OPCo filed its 2013 SEET filing with the PUCO. In October 2014, OPCo entered into a stipulation agreement with the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2013 for OPCo. A hearing at the PUCO related to the 2013 SEET filing is scheduled for November 2014.

Management believes its financial statements adequately address the impact of SEET requirements.


55



Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo’s generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition.

Storm Damage Recovery Rider (SDRR)

In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates to recover 2012 incremental storm distribution expenses. In April 2014, the PUCO approved a stipulation agreement between OPCo, the PUCO staff and all intervenors, except the Ohio Consumers’ Counsel, to recover $55 million over a 12-month period. The agreement also provided that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period. Compliance tariffs were filed with the PUCO and new rates were implemented in April 2014. In May 2014, the PUCO upheld the settlement agreement on rehearing.

2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.

In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges. In September 2014, the Supreme Court of Ohio upheld the PUCO order. A review of the coal reserve valuation by an outside consultant is still pending. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC). The PUCO subsequently ruled in the PIRR proceeding that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes. See the 2009 - 2011 ESP section of “Ohio Electric Security Plan Filings” above for a discussion of the PUCO order in the PIRR proceeding. In May 2014, the PUCO issued an order that generally approved OPCo's 2010-2011 fuel costs and rejected the auditor recommendation to adjust the WACC carrying charges related to accumulated deferred income taxes. Additionally, the PUCO requested further review related to an affiliate barging agreement and the modification of certain fuel procurement processes and practices. Further, the order provided for the auditor to address any remaining concerns in their next audit report, as they deem necessary. In July 2014, the PUCO issued an order that denied all requests for rehearing.


56



2012 and 2013 Fuel Adjustment Clause Audits

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

Ormet

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

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

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

Ohio IGCC Plant

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

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


57



SWEPCo Rate Matters

2012 Texas Base Rate Case

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

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

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

Texas Transmission Cost Recovery Factor Filing

In May 2014, SWEPCo filed an application with the PUCT to implement its transmission cost recovery factor (TCRF) requesting additional annual revenue of $15 million. The TCRF is designed to recover increases from the amounts included in SWEPCo’s Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC. SWEPCo’s application included Turk Plant transmission-related costs. In July 2014, intervenors filed testimony with recommendations that included revenue increases ranging from $1 million to $10 million. Hearings at the PUCT were held in August 2014. In October 2014, the Administrative Law Judge issued a proposal for decision that recommended approval of SWEPCo's application with an increase in annual revenue of $14 million. An order is anticipated in the fourth quarter of 2014. If the PUCT were to disallow any portion of the TCRF, it could reduce future net income and cash flows and impact financial condition.

2012 Louisiana Formula Rate Filing

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


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2014 Louisiana Formula Rate Filing

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

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC.  Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC.  As of September 30, 2014, SWEPCo has incurred costs of $112 million and has contractual construction obligations of $84 million related to these projects.  SWEPCo will seek to recover these project costs from customers through filings at the state commissions and FERC. These environmental projects could be adversely impacted by pending carbon emission regulations.  As of September 30, 2014, the net book value of Welsh Plant, Units 1 and 3 was $335 million, before cost of removal, including materials and supplies inventory and CWIP.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 

APCo and WPCo Rate Matters

Plant Transfer

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a cost-of-service basis. West Virginia generally allows for timely recovery of fuel costs through an expanded net energy cost which trues-up to actual expenses. In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo until APCo's West Virginia base rates are updated. See the "2014 West Virginia Base Rate Case" below. In April 2014, AGR and WPCo filed a request with the FERC for approval to transfer AGR’s one-half interest in the Mitchell Plant to WPCo. In June 2014, the FERC issued an order approving this request.

In August 2014, intervenors filed testimony with the WVPSC with recommendations that ranged from transferring only a portion of the one-half interest in the Mitchell Plant to denial of the transfer in its entirety. Additionally, recommendations included reducing the net book value of the one-half interest in the Mitchell Plant and reducing the base rate surcharge to $87 million. Intervenors also expressed concerns related to the amount of liability assumed by WPCo should the transfer be approved. In October 2014, a stipulation agreement between APCo, WPCo, the WVPSC staff and intervenors in the case was filed with the WVPSC. The stipulation agreement recommended approval for WPCo to acquire, at net book value, the one-half interest in the Mitchell Plant, excluding $20 million of certain assets, which will be paid by WPCo and recovered as a regulatory asset over the life of the plant. Additionally, the agreement stated that 82.5% of the costs associated with the acquired interest will be reflected in rates effective from the date of the transfer via a surcharge with an offset in ENEC revenues. The remaining 17.5% of the costs associated with the acquired interest is to be included in rates by January 2020. The agreement also proposed that WPCo share the energy margins for 82.5% of the plant’s output with ratepayers and that WPCo retain all of the energy margins from sales into the wholesale market on the remaining 17.5%, to offset fixed costs associated with this portion, until the remaining portion is approved for inclusion in rates. Management anticipates an order related to the proposed transfer will be issued in the fourth quarter of 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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APCo IGCC Plant

As of September 30, 2014, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $10 million applicable to its Virginia jurisdiction.  In March 2014, APCo submitted a request to the Virginia SCC as part of the 2014 Virginia Biennial Base Rate Case to amortize the Virginia jurisdictional share of these costs over two years. In June 2014, APCo submitted a request to the WVPSC as part of the 2014 West Virginia Base Rate Case to amortize the West Virginia jurisdictional share of these costs over five years. In August 2014, intervenors filed testimony with the Virginia SCC that recommended APCo write-off the entire $10 million applicable to the Virginia jurisdiction. Hearings at the Virginia SCC were held in September 2014. A decision is expected in November 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Transmission Rate Adjustment Clause (transmission RAC)

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

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a biennial generation and distribution base rate case with the Virginia SCC. In accordance with a Virginia statute, APCo did not request a change in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to changes in the expected service lives of various generating units and the extended recovery through 2040 of the net book value of certain planned 2015 plant retirements. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to IGCC and other deferred costs.

In August 2014, the Virginia SCC staff and intervenors filed testimony concluding that APCo's adjusted earned rate of return on common equity for 2012 and 2013, reflecting their recommended adjustments, was above the allowed threshold. Recommendations included (a) refunds to customers ranging from $15 million to $22 million, (b) the write-off of certain APCo assets, including IGCC pre-construction costs and previously approved 2009 storm costs, totaling $27 million and (c) $38 million in increased depreciation expense annually, retroactive to January 1, 2014, primarily related to accelerating depreciation on APCo generation assets to be retired in the second quarter of 2015. Hearings at the Virginia SCC were held in September 2014. A decision is expected in November 2014. If any of these costs are not recoverable, or if refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

2014 West Virginia Base Rate Case

In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $181 million, based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units. The filing also requested recovery of $89 million over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $45 million annually to recover vegetation management costs, including a return on capital investment. In October 2014, the WVPSC approved APCo's motion to revise the procedural schedule which included the extension of the intervention period to November 2014 and a delay in the implementation of new rates from April 2015 to May 2015. Hearings at the WVPSC are scheduled for January 2015. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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PSO Rate Matters

2014 Oklahoma Base Rate Case

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

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

In June 2014, a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors was filed with the OCC. The parties to the stipulation recommended no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider would provide $7 million of revenues in 2014 and increase to $27 million in 2016. New depreciation rates are recommended for advanced metering investments and existing meters, also to be effective November 2014. Further, the stipulation recommends a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component. Additionally, the stipulation recommends recovery of regulatory assets for 2013 storms and regulatory case expenses. In July 2014, the Attorney General joined in the stipulation agreement. A hearing at the OCC was held in July 2014. An order is anticipated in the fourth quarter of 2014. If the OCC were to disallow any portion of this settlement agreement, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2% and adjusted the authorized annual increase in base rates to $92 million in March 2013. In April 2014, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal to the Indiana Supreme Court related to the inclusion of a prepaid pension asset in rate base, which is approximately $7 million in annual revenues. In August 2014, the Indiana Supreme Court denied the appeal filed by the OUCC.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of September 30, 2014, I&M has incurred costs of $492 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined

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in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In May 2014, the IURC issued a final order approving the LCM rider rates that were implemented in January 2014.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project. In October 2014, the Michigan Court of Appeals issued an order that affirmed the MPSC decision in part, but reversed the portion of the MPSC decision related to certain costs. The order indicated that I&M could recover those costs in a future Michigan base case if they can show that the costs were reasonable and prudent.

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

Tanners Creek Plant

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

In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015. Upon the retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant.

In September 2014, a settlement agreement was approved by the MPSC that included the authorization for I&M to implement revised depreciation rates for Rockport Plant, Unit 1, effective upon the retirement date of the Tanners Creek Plant. Upon implementation of the revised depreciation rates, I&M is authorized to reduce customer rates through a credit rider until the revised rates for Rockport Plant, Unit 1 are included in base rates.

Transmission, Distribution and Storage System Improvement Charge (TDSIC)

In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan, from 2015 through 2021, for eligible transmission, distribution and storage system improvements. The initial estimated cost of the capital improvements and associated operation and maintenance expenses included in the TDSIC Plan of $787 million will be updated annually. The TDSIC Plan included distribution investments specific to the Indiana jurisdiction. The TDSIC Rider will allow the periodic adjustment of I&M's rates to provide for timely recovery of 80% of approved TDSIC Plan costs. I&M will defer the remaining 20% of approved TDSIC Plan costs to be recovered in I&M's next general rate case. I&M is not seeking a rate adjustment in this proceeding but is seeking approval of a TDSIC Rider rate adjustment mechanism for subsequent proceedings. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


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KPCo Rate Matters

Plant Transfer

In December 2012, KPCo filed a request with the KPSC for approval to transfer at net book value to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. KPCo also requested that costs related to the Big Sandy Plant, Unit 2 FGD project be established as a regulatory asset. As of September 30, 2014, the net book value of Big Sandy Plant, Unit 2 was $273 million, before cost of removal, including materials and supplies inventory and CWIP.

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

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

Kentucky Fuel Adjustment Clause Review

In August 2014, the KPSC issued an order initiating a review of KPCo's FAC from November 2013 through April 2014. An intervenor has requested and received a revised procedural schedule to determine if the allocation of fuel costs has been applied appropriately. In October 2014, intervenors filed testimony that recommended the KPSC direct KPCo to modify its fuel allocation methodology and order a refund to customers of approximately $13 million, plus carrying charges at a weighted average cost of capital, related to the period January 1, 2014 through April 30, 2014. A hearing at the KPSC is scheduled for November 2014. Management believes the methodology used to determine fuel costs is appropriate and intends to oppose the recommendations filed by intervenors. If the KPSC directs KPCo to modify its fuel allocation methodology, it could affect the allocation of costs for all periods beginning January 2014, and if any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.




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5.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

We are subject to certain claims and legal actions arising in our ordinary course of business.  In addition, our business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation against us cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on our financial statements.  The Commitments, Guarantees and Contingencies note within our 2013 Annual Report should be read in conjunction with this report.

GUARANTEES

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

Letters of Credit

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

We have two revolving credit facilities totaling $3.5 billion, under which we may issue up to $1.2 billion as letters of credit.  As of September 30, 2014, the maximum future payments for letters of credit issued under the revolving credit facilities were $76 million with maturities ranging from October 2014 to June 2015.

In January 2014, we issued letters of credit under an $85 million uncommitted facility signed in October 2013. As of September 30, 2014, the maximum future payments for letters of credit issued under the uncommitted facility were $78 million with maturities ranging from October 2014 to January 2015. An uncommitted facility gives the issuer of the facility the right to accept or decline each request we make under the facility.

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

Guarantees of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study completed in 2010, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation.  As of September 30, 2014, SWEPCo has collected approximately $63 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $47 million is recorded in Asset Retirement Obligations on our condensed balance sheets.

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


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Indemnifications and Other Guarantees

Contracts

We enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, our exposure generally does not exceed the sale price.  As of September 30, 2014, there were no material liabilities recorded for any indemnifications.

Master Lease Agreements

We lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, we are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.  As of September 30, 2014, the maximum potential loss for these lease agreements was approximately $24 million assuming the fair value of the equipment is zero at the end of the lease term.

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignments are accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $12 million and $14 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2014.

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

ENVIRONMENTAL CONTINGENCIES

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

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

In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M started remediation work in accordance with a plan approved by MDEQ.  In September 2014, I&M

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recorded an accrual for remediation at certain additional sites in Michigan. As of September 30, 2014, I&M’s accrual for all of these sites is approximately $17 million.  As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation.  We cannot predict the amount of additional cost, if any.

NUCLEAR CONTINGENCIES

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

OPERATIONAL CONTINGENCIES

Rockport Plant Litigation

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

Natural Gas Markets Lawsuits

In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity.  AEP was dismissed from the case.  A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies.  AEP (or a subsidiary) is among the companies named as defendants in some of these cases.  We settled, received summary judgment or were dismissed from all of these cases.  The plaintiffs appealed the Nevada federal district court's dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit.  In April 2013, the appellate court reversed in part, and affirmed in part, the district court's orders in these cases.  The appellate court reversed the district court's holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases.  Defendants in these cases, including AEP, previously filed a petition seeking further review with the U.S. Supreme Court on the preemption issue. In June 2014, AEP filed a petition with the U.S. Supreme Court seeking review of the personal jurisdiction issue. In July 2014, the U.S. Supreme Court granted the defendants' previously filed petition for further review with the U.S. Supreme Court on the preemption issue.  We will continue to defend the cases.  We believe the provision we have is adequate. We are unable to determine the amount of potential additional losses that are reasonably possible of occurring.


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Wage and Hours Lawsuit

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

In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action.  Notice was given to all potential class members and an additional 43 individuals opted in to the class, bringing the plaintiff class to 79 current and former employees. We will continue to defend the case. We are unable to determine a range of potential losses that are reasonably possible of occurring.

National Do Not Call Registry Lawsuit

In May 2014, AEP Energy was served with a complaint filed in the U.S. District Court for the Northern District of Illinois, alleging violations of the Telephone Consumer Protection Act (TCPA). The plaintiff alleges that he received telemarketing calls on behalf of AEP Energy despite having registered his telephone number on the National Do Not Call Registry. Plaintiff seeks to represent a class of persons who allegedly received such calls. Plaintiff seeks statutory damages under the TCPA on behalf of himself and the alleged class as well as injunctive relief. We will continue to defend this case. We believe the provision we have is adequate. We are unable to determine the amount of potential additional losses that are reasonably possible of occurring.
Gavin Landfill Litigation
In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill.  The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors.  Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims.  The plaintiffs seek compensatory and punitive damages, as well as medical monitoring.  In September 2014, we filed a motion to dismiss the complaint, contending the case should be filed in Ohio.  That motion is pending.  We will continue to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

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6.  IMPAIRMENTS

2013

Turk Plant (Vertically Integrated Utilities segment)

In the third quarter of 2013, SWEPCo recorded a pretax write-off of $111 million in Asset Impairments and Other Related Charges on the statement of income related to AFUDC on the Turk Plant that was included in the Texas capital cost cap. See the "2012 Texas Base Rate Case" section of Note 4.

Big Sandy Plant, Unit 2 FGD Project (Vertically Integrated Utilities segment)

In the third quarter of 2013, KPCo recorded a pretax write-off of $33 million in Asset Impairments and Other Related Charges on the statement of income primarily related to the Big Sandy Plant, Unit 2 FGD project. See the "Plant Transfer" section of KPCo Rate Matters in Note 4.

Muskingum River Plant, Unit 5 (Generation & Marketing segment)

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


68



7.  BENEFIT PLANS

Components of Net Periodic Benefit Cost

The following tables provide the components of our net periodic benefit cost (credit) for the plans for the three and nine months ended September 30, 2014 and 2013:
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions)
Service Cost
$
18

 
$
17

 
$
4

 
$
5

Interest Cost
55

 
51

 
16

 
18

Expected Return on Plan Assets
(65
)
 
(69
)
 
(28
)
 
(27
)
Amortization of Prior Service Cost (Credit)
1

 
1

 
(18
)
 
(17
)
Amortization of Net Actuarial Loss
31

 
45

 
6

 
16

Net Periodic Benefit Cost (Credit)
$
40

 
$
45

 
$
(20
)
 
$
(5
)
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions)
Service Cost
$
54

 
$
52

 
$
11

 
$
17

Interest Cost
166

 
152

 
50

 
53

Expected Return on Plan Assets
(196
)
 
(208
)
 
(84
)
 
(80
)
Amortization of Prior Service Cost (Credit)
2

 
2

 
(52
)
 
(52
)
Amortization of Net Actuarial Loss
93

 
137

 
17

 
48

Net Periodic Benefit Cost (Credit)
$
119

 
$
135

 
$
(58
)
 
$
(14
)


69



8.  BUSINESS SEGMENTS

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

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

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

Vertically Integrated Utilities

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

Transmission and Distribution Utilities

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

AEP Transmission Holdco

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

Generation & Marketing

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

AEP River Operations

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

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


70



The tables below present our reportable segment income statement information for the three and nine months ended September 30, 2014 and 2013 and reportable segment balance sheet information as of September 30, 2014 and December 31, 2013.  These amounts include certain estimates and allocations where necessary.
 
 
Vertically Integrated Utilities

Transmission and Distribution Utilities

AEP Transmission Holdco

Generation
&
Marketing

AEP River Operations

Corporate and Other (a)

Reconciling Adjustments

Consolidated
 
 
(in millions)
Three Months Ended 
 September 30, 2014
 
 

 
 

 
 

 
 

 
 

 
 

 
 
 
 

Revenues from:
 
 

 
 

 
 

 
 

 
 

 
 

 
 
 
 

External Customers
 
$
2,432

(b)
$
1,163

 
$
21

 
$
538

(b)
$
141

 
$
7

 
$

(c)
$
4,302

Other Operating Segments
 
18

(b)
68

 
34

 
363

(b)
14

 
19

 
(516
)
 

Total Revenues
 
$
2,450

 
$
1,231

 
$
55

 
$
901

 
$
155

 
$
26

 
$
(516
)
 
$
4,302


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income
 
$
220

 
$
92

 
$
43

 
$
117

 
$
11

 
$
11

 
$

 
$
494

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vertically Integrated Utilities
 
Transmission and Distribution Utilities
 
AEP Transmission Holdco
 
Generation
&
Marketing
 
AEP River Operations
 
Corporate and Other (a)
 
Reconciling Adjustments
 
Consolidated
 
 
(in millions)
Three Months Ended 
 September 30, 2013
 
 

 
 

 
 

 
 

 
 

 
 

 
 
 
 

Revenues from:
 
 

 
 

 
 

 
 

 
 

 
 

 
 
 
 

External Customers
 
$
2,543

 
$
1,139

 
$
9

 
$
359

 
$
126

 
$
12

 
$
(12
)
(c)
$
4,176

Other Operating Segments
 
195

 
56

 
17

 
642

 
4

 
16

 
(930
)
 

Total Revenues
 
$
2,738

 
$
1,195

 
$
26

 
$
1,001

 
$
130

 
$
28

 
$
(942
)
 
$
4,176

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
$
174

 
$
119

 
$
22

 
$
112

 
$
(1
)
 
$
8

 
$

 
$
434



71



 
 
Vertically Integrated Utilities
 
Transmission and Distribution Utilities
 
AEP Transmission Holdco
 
Generation
&
Marketing
 
AEP River Operations
 
Corporate and Other (a)
 
Reconciling Adjustments
 
Consolidated
 
 
(in millions)
Nine Months Ended 
 September 30, 2014
 
 

 
 

 
 
 
 

 
 

 
 

 
 

 
 

Revenues from:
 
 

 
 

 
 
 
 

 
 

 
 

 
 

 
 

External Customers
 
$
7,217

(b)
$
3,388

 
$
54

 
$
1,932

(b)
$
435

 
$
19

 
$
(51
)
(c)
$
12,994

Other Operating Segments
 
71

(b)
192

 
86

 
1,133

(b)
45

 
55

 
(1,582
)
 

Total Revenues
 
$
7,288

 
$
3,580

 
$
140

 
$
3,065

 
$
480

 
$
74

 
$
(1,633
)
 
$
12,994

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income
 
$
654

 
$
279

 
$
114

 
$
378

 
$
17

 
$
4

 
$

 
$
1,446

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vertically Integrated Utilities
 
Transmission and Distribution Utilities
 
AEP Transmission Holdco
 
Generation
&
Marketing
 
AEP River Operations
 
Corporate and Other (a)
 
Reconciling Adjustments
 
Consolidated
 
 
(in millions)
Nine Months Ended 
 September 30, 2013
 
 

 
 

 
 
 
 

 
 

 
 

 
 

 
 

Revenues from:
 
 

 
 

 
 
 
 

 
 

 
 

 
 

 
 

External Customers
 
$
7,075

 
$
3,248

 
$
18

 
$
915

 
$
365

 
$
26

 
$
(63
)
(c)
$
11,584

Other Operating Segments
 
480

 
145

 
35

 
1,898

 
15

 
41

 
(2,614
)
 

Total Revenues
 
$
7,555

 
$
3,393

 
$
53

 
$
2,813

 
$
380

 
$
67

 
$
(2,677
)
 
$
11,584

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
$
508

 
$
281

 
$
53

 
$
188

 
$
(12
)
 
$
119

 
$

 
$
1,137



72



 
 
Vertically Integrated Utilities

Transmission and Distribution Utilities

AEP Transmission Holdco

Generation
&
Marketing

AEP River Operations

Corporate and Other (a)

Reconciling
Adjustments

Consolidated
 
 
(in millions)
September 30, 2014
 
 

 
 

 
 

 
 

 
 
 
 

 
 

 
 

Total Property, Plant and Equipment
 
$
38,857

 
$
12,792

 
$
2,378

 
$
8,363

 
$
673

 
$
331

 
$
(271
)
(d)
$
63,123

Accumulated Depreciation and Amortization
 
12,728

 
3,447

 
20

 
3,563

 
212

 
183

 
(94
)
(d)
20,059

Total Property Plant and Equipment - Net
 
$
26,129

 
$
9,345

 
$
2,358

 
$
4,800

 
$
461

 
$
148

 
$
(177
)
(d)
$
43,064

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
33,072

 
$
13,822

 
$
3,000

 
$
6,280

 
$
686

 
$
20,706

 
$
(19,641
)
(d) (e)
$
57,925

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt Due Within One Year:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliated
 
$
131

 
$

 
$

 
$
86

 
$

 
$

 
$
(217
)
 
$

Non-Affiliated
 
1,309

 
405

 

 
661

 
3

 
3

 

 
2,381

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliated
 
20

 

 

 
32

 

 

 
(52
)
 

Non-Affiliated
 
8,574

 
5,189

 
699

 
297

 
81

 
837

 

 
15,677

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Long-term Debt
 
$
10,034

 
$
5,594

 
$
699

 
$
1,076

 
$
84

 
$
840

 
$
(269
)
 
$
18,058

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vertically Integrated Utilities
 
Transmission and Distribution Utilities
 
AEP Transmission Holdco
 
Generation
&
Marketing
 
AEP River Operations
 
Corporate and Other (a)
 
Reconciling
Adjustments
 
Consolidated
 
 
(in millions)
December 31, 2013
 
 

 
 

 
 

 
 

 
 
 
 

 
 

 
 

Total Property, Plant and Equipment
 
$
37,545

 
$
12,143

 
$
1,636

 
$
8,277

 
$
638

 
$
315

 
$
(269
)
(d)
$
60,285

Accumulated Depreciation and Amortization
 
12,250

 
3,342

 
10

 
3,409

 
189

 
173

 
(85
)
(d)
19,288

Total Property Plant and Equipment - Net
 
$
25,295

 
$
8,801

 
$
1,626

 
$
4,868

 
$
449

 
$
142

 
$
(184
)
(d)
$
40,997

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
32,791

 
$
14,165

 
$
2,245

 
$
6,426

 
$
673

 
$
19,645

 
$
(19,531
)
(d) (e)
$
56,414

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt Due Within One Year:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliated
 
$

 
$

 
$

 
$
179

 
$
5

 
$

 
$
(184
)
 
$

Non-Affiliated
 
720

 
697

 

 
126

 
2

 
4

 

 
1,549

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliated
 
151

 

 

 
118

 
10

 

 
(279
)
 

Non-Affiliated
 
9,265

 
5,360

 
620

 
664

 
83

 
836

 

 
16,828

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Long-term Debt
 
$
10,136

 
$
6,057

 
$
620

 
$
1,087

 
$
100

 
$
840

 
$
(463
)
 
$
18,377


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


73



9.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

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

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

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

Notional Volume of Derivative Instruments
 
 
Volume
 
 
 
 
September 30,
2014
 
December 31,
2013
 
Unit of
Measure
Primary Risk Exposure
 
(in millions)
 
 
Commodity:
 
 
 
 

 
 
Power
 
348

 
406

 
MWhs
Coal
 
2

 
4

 
Tons
Natural Gas
 
112

 
127

 
MMBtus
Heating Oil and Gasoline
 
5

 
6

 
Gallons
Interest Rate
 
$
162

 
$
191

 
USD
 
 
 
 
 
 
 
Interest Rate and Foreign Currency
 
$
815

 
$
820

 
USD


74




Fair Value Hedging Strategies

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

Cash Flow Hedging Strategies

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

Our vehicle fleet and barge operations are exposed to gasoline and diesel fuel price volatility. We enter into financial heating oil and gasoline derivative contracts in order to mitigate price risk of our future fuel purchases. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014. During the three and nine months ended September 30, 2013, we designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. We do not hedge all fuel price risk.

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

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

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

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

75



flows if market prices are not consistent with our estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of our risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2014 and December 31, 2013 condensed balance sheets, we netted $20 million and $4 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $6 million and $13 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

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

Fair Value of Derivative Instruments
September 30, 2014
 
 
Risk
Management
Contracts
 
Hedging Contracts
 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Interest Rate
and Foreign
Currency (a)
 
 
 
 
 
(in millions)
Current Risk Management Assets
 
$
340

 
$
17

 
$
4

 
$
361

 
$
(226
)
 
$
135

Long-term Risk Management Assets
 
300

 
4

 

 
304

 
(76
)
 
228

Total Assets
 
640

 
21

 
4

 
665

 
(302
)
 
363

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
262

 
12

 
1

 
275

 
(215
)
 
60

Long-term Risk Management Liabilities
 
180

 
3

 
12

 
195

 
(75
)
 
120

Total Liabilities
 
442

 
15

 
13

 
470

 
(290
)
 
180

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
198

 
$
6

 
$
(9
)
 
$
195

 
$
(12
)
 
$
183

 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
Management
Contracts
 
Hedging Contracts
 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Interest Rate
and Foreign
Currency (a)
 
 
 
 
 
(in millions)
Current Risk Management Assets
 
$
347

 
$
12

 
$
4

 
$
363

 
$
(203
)
 
$
160

Long-term Risk Management Assets
 
368

 
3

 

 
371

 
(74
)
 
297

Total Assets
 
715

 
15

 
4

 
734

 
(277
)
 
457

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
292

 
11

 
1

 
304

 
(214
)
 
90

Long-term Risk Management Liabilities
 
237

 
3

 
15

 
255

 
(78
)
 
177

Total Liabilities
 
529

 
14

 
16

 
559

 
(292
)
 
267

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
186

 
$
1

 
$
(12
)
 
$
175

 
$
15

 
$
190


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


76



The table below presents our activity of derivative risk management contracts for the three and nine months ended September 30, 2014 and 2013:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three and Nine Months Ended September 30, 2014 and 2013
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Location of Gain (Loss)
 
2014
 
2013
 
2014
 
2013
 
 
(in millions)
Vertically Integrated Utilities Revenues
 
$
7

 
$
3

 
$
29

 
$
13

Generation & Marketing Revenues
 
21

 
10

 
69

 
43

Regulatory Assets (a)
 
(6
)
 
(1
)
 
(6
)
 
(3
)
Regulatory Liabilities (a)
 
(7
)
 
(4
)
 
111

 
(10
)
Total Gain on Risk Management Contracts
 
$
15

 
$
8

 
$
203

 
$
43


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

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

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

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

Accounting for Fair Value Hedging Strategies

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

We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our condensed statements of income. During the three and nine months ended September 30, 2014, we recognized losses of $2 million and gains of $2 million, respectively, on our hedging instruments and offsetting gains of $2 million and losses of $2 million, respectively, on our long-term debt.  During the three and nine months ended September 30, 2013, we recognized gains of $4 million and losses of $8 million, respectively, on our hedging instruments and offsetting losses of $4 million and gains of $8 million, respectively, on our long-term debt.  During the three and nine months ended September 30, 2014 and 2013, hedge ineffectiveness was immaterial.


77



Accounting for Cash Flow Hedging Strategies

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

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on our condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2014 and 2013, we designated power, coal and natural gas derivatives as cash flow hedges.

We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our condensed statements of income. During the three and nine months ended September 30, 2013, we designated heating oil and gasoline derivatives as cash flow hedges. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Interest Expense on our condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2014 and 2013, we designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Depreciation and Amortization expense on our condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2014 and 2013, we did not designate any foreign currency derivatives as cash flow hedges. 

During the three and nine months ended September 30, 2014 and 2013, hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies disclosed above.

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2014 and 2013, see Note 3.


78



Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2014 and December 31, 2013 were:
Impact of Cash Flow Hedges on the Condensed Balance Sheet
September 30, 2014
 
 
 
 
 
 
 
Commodity
 
Interest Rate
and Foreign
Currency
 
Total
 
(in millions)
Hedging Assets (a)
$
9

 
$

 
$
9

Hedging Liabilities (a)
3

 
1

 
4

AOCI Gain (Loss) Net of Tax
3

 
(20
)
 
(17
)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months
2

 
(3
)
 
(1
)
 
 
 
 
 
 
Impact of Cash Flow Hedges on the Condensed Balance Sheet
December 31, 2013
 
 
 
 
 
 
 
Commodity
 
Interest Rate
and Foreign
Currency
 
Total
 
(in millions)
Hedging Assets (a)
$
7

 
$

 
$
7

Hedging Liabilities (a)
6

 
2

 
8

AOCI Loss Net of Tax

 
(23
)
 
(23
)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months

 
(4
)
 
(4
)

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

The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.  As of September 30, 2014, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions was 63 months.

Credit Risk

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

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


79



Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs), a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, and guaranties for contractual obligations, we are obligated to post an additional amount of collateral if our credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and our total exposure. On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP and its subsidiaries have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. The following table represents: (a) our fair value of such derivative contracts, (b) the amount of collateral we would have been required to post for all derivative and non-derivative contracts and guaranties for contractual obligations if our credit ratings had declined below a specified rating threshold and (c) how much was attributable to RTO and ISO activities as of September 30, 2014 and December 31, 2013:
 
September 30,
2014
 
December 31,
2013
 
(in millions)
Liabilities for Derivative Contracts with Credit Downgrade Triggers
$
1

 
$
3

Amount of Collateral AEP Subsidiaries Would Have Been Required to Post
144

 
33

Amount Attributable to RTO and ISO Activities
35

 
28


In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million.  On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts. The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of September 30, 2014 and December 31, 2013:
 
September 30,
2014
 
December 31,
2013
 
(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements
$
189

 
$
293

Amount of Cash Collateral Posted

 
1

Additional Settlement Liability if Cross Default Provision is Triggered
147

 
235



80



10.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

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

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

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

Assets in the nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds.  Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation

81



inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

Fair Value Measurements of Long-term Debt

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

The book values and fair values of Long-term Debt as of September 30, 2014 and December 31, 2013 are summarized in the following table:
 
September 30, 2014
 
December 31, 2013
 
Book Value
 
Fair Value
 
Book Value
 
Fair Value
 
(in millions)
Long-term Debt
$
18,058

 
$
20,237

 
$
18,377

 
$
19,672


Fair Value Measurements of Other Temporary Investments

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

The following is a summary of Other Temporary Investments:
 
 
September 30, 2014
Other Temporary Investments
 
Cost
 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Estimated
Fair
Value
 
 
(in millions)
Restricted Cash (a)
 
$
213

 
$

 
$

 
$
213

Fixed Income Securities  Mutual Funds
 
80

 

 

 
80

Equity Securities  Mutual Funds
 
13

 
12

 

 
25

Total Other Temporary Investments
 
$
306

 
$
12

 
$

 
$
318

 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
Other Temporary Investments
 
Cost
 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Estimated
Fair
Value
 
 
(in millions)
Restricted Cash (a)
 
$
250

 
$

 
$

 
$
250

Fixed Income Securities  Mutual Funds
 
80

 

 

 
80

Equity Securities  Mutual Funds
 
12

 
11

 

 
23

Total Other Temporary Investments
 
$
342

 
$
11

 
$

 
$
353


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


82



The following table provides the activity for our fixed income and equity securities within Other Temporary Investments for the three and nine months ended September 30, 2014 and 2013:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions)
Proceeds from Investment Sales
$

 
$

 
$

 
$

Purchases of Investments

 
6

 
1

 
17

Gross Realized Gains on Investment Sales

 

 

 

Gross Realized Losses on Investment Sales

 

 

 


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

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

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

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

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

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

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


83



The following is a summary of nuclear trust fund investments as of September 30, 2014 and December 31, 2013:
 
September 30, 2014
 
December 31, 2013
 
Estimated
Fair
Value
 
Gross
Unrealized
Gains
 
Other-Than-
Temporary
Impairments
 
Estimated
Fair
Value
 
Gross
Unrealized
Gains
 
Other-Than-
Temporary
Impairments
 
(in millions)
Cash and Cash Equivalents
$
13

 
$

 
$

 
$
19

 
$

 
$

Fixed Income Securities:
 

 
 

 
 

 
 
 
 

 
 

United States Government
609

 
35

 
(3
)
 
609

 
26

 
(4
)
Corporate Debt
46

 
4

 
(1
)
 
37

 
2

 
(1
)
State and Local Government
286

 
1

 

 
255

 
1

 

Subtotal Fixed Income Securities
941

 
40

 
(4
)
 
901

 
29

 
(5
)
Equity Securities  Domestic
1,066

 
545

 
(80
)
 
1,012

 
506

 
(82
)
Spent Nuclear Fuel and Decommissioning Trusts
$
2,020

 
$
585

 
$
(84
)
 
$
1,932

 
$
535

 
$
(87
)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2014 and 2013:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions)
Proceeds from Investment Sales
$
263

 
$
250

 
$
746

 
$
635

Purchases of Investments
281

 
264

 
790

 
676

Gross Realized Gains on Investment Sales
8

 
4

 
25

 
16

Gross Realized Losses on Investment Sales
1

 
2

 
10

 
12


The adjusted cost of fixed income securities was $901 million and $872 million as of September 30, 2014 and December 31, 2013, respectively.  The adjusted cost of equity securities was $521 million and $506 million as of September 30, 2014 and December 31, 2013, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2014 was as follows:
 
Fair Value of
Fixed Income
Securities
 
(in millions)
Within 1 year
$
103

1 year – 5 years
377

5 years – 10 years
198

After 10 years
263

Total
$
941



84



Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2014 and December 31, 2013.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in our valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2014
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
$
22

 
$
1

 
$

 
$
171

 
$
194

 
 
 
 
 
 
 
 
 
 
 
Other Temporary Investments
 
 
 
 
 
 
 
 
 
 
Restricted Cash (a)
 
196

 
8

 

 
9

 
213

Fixed Income Securities - Mutual Funds
 
80

 

 

 

 
80

Equity Securities  Mutual Funds (b)
 
25

 

 

 

 
25

Total Other Temporary Investments
 
301

 
8

 

 
9

 
318

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (c) (d)
 
13

 
441

 
155

 
(261
)
 
348

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (c)
 

 
16

 
4

 
(11
)
 
9

Fair Value Hedges
 

 
1

 

 
3

 
4

De-designated Risk Management Contracts (e)
 

 

 

 
2

 
2

Total Risk Management Assets
 
13

 
458

 
159

 
(267
)
 
363

 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 

 
 

 
 

 
 

 
 

Cash and Cash Equivalents (f)
 
4

 

 

 
9

 
13

Fixed Income Securities:
 
 

 
 

 
 

 
 

 
 

United States Government
 

 
609

 

 

 
609

Corporate Debt
 

 
46

 

 

 
46

State and Local Government
 

 
286

 

 

 
286

Subtotal Fixed Income Securities
 

 
941

 

 

 
941

Equity Securities  Domestic (b)
 
1,066

 

 

 

 
1,066

Total Spent Nuclear Fuel and Decommissioning Trusts
 
1,070

 
941

 

 
9

 
2,020

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
1,406

 
$
1,408

 
$
159

 
$
(78
)
 
$
2,895

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (c) (d)
 
$
26

 
$
355

 
$
30

 
$
(247
)
 
$
164

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (c)
 

 
14

 

 
(11
)
 
3

Interest Rate/Foreign Currency Hedges
 

 
1

 

 

 
1

Fair Value Hedges
 

 
9

 

 
3

 
12

Total Risk Management Liabilities
 
$
26

 
$
379

 
$
30

 
$
(255
)
 
$
180



85



Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
$
16

 
$
1

 
$

 
$
101

 
$
118

 
 
 
 
 
 
 
 
 
 
 
Other Temporary Investments
 
 
 
 
 
 
 
 
 
 
Restricted Cash (a)
 
231

 
8

 

 
11

 
250

Fixed Income Securities - Mutual Funds
 
80

 

 

 

 
80

Equity Securities  Mutual Funds (b)
 
23

 

 

 

 
23

Total Other Temporary Investments
 
334

 
8

 

 
11

 
353

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (c) (g)
 
22

 
549

 
142

 
(273
)
 
440

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (c)
 

 
15

 

 
(8
)
 
7

Fair Value Hedges
 

 
1

 

 
3

 
4

De-designated Risk Management Contracts (e)
 

 

 

 
6

 
6

Total Risk Management Assets
 
22

 
565

 
142

 
(272
)
 
457

 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 

 
 

 
 

 
 

 
 

Cash and Cash Equivalents (f)
 
8

 

 

 
11

 
19

Fixed Income Securities:
 
 

 
 

 
 

 
 

 
 

United States Government
 

 
609

 

 

 
609

Corporate Debt
 

 
37

 

 

 
37

State and Local Government
 

 
255

 

 

 
255

Subtotal Fixed Income Securities
 

 
901

 

 

 
901

Equity Securities  Domestic (b)
 
1,012

 

 

 

 
1,012

Total Spent Nuclear Fuel and Decommissioning Trusts
 
1,020

 
901

 

 
11

 
1,932

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
1,392

 
$
1,475

 
$
142

 
$
(149
)
 
$
2,860

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (c) (g)
 
$
30

 
$
475

 
$
22

 
$
(282
)
 
$
245

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (c)
 

 
11

 
3

 
(8
)
 
6

Interest Rate/Foreign Currency Hedges
 

 
2

 

 

 
2

Fair Value Hedges
 

 
11

 

 
3

 
14

Total Risk Management Liabilities
 
$
30

 
$
499

 
$
25

 
$
(287
)
 
$
267


(a)
Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties.  Level 1 and Level 2 amounts primarily represent investments in money market funds.
(b)
Amounts represent publicly traded equity securities and equity-based mutual funds.
(c)
Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.''
(d)
The September 30, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures ($12) million in periods 2015-2017 and ($1) million in periods 2018-2019;  Level 2 matures $6 million in 2014, $67 million in periods 2015-2017, $9 million in periods 2018-2019 and $4 million in periods 2020-2030;  Level 3 matures $38 million in 2014, $46 million in periods 2015-2017, $16 million in periods 2018-2019 and $25 million in periods 2020-2030.  Risk management commodity contracts are substantially comprised of power contracts.
(e)
Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for ''Derivatives and Hedging.''  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This MTM value will be amortized into revenues over the remaining life of the contracts.
(f)
Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(g)
The December 31, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $4 million in 2014, ($11) million in periods 2015-2017 and ($1) million in periods 2018-2019;  Level 2 matures $25 million in 2014, $37 million in periods 2015-2017, $7 million in periods 2018-2019 and $5 million in periods 2020-2030;  Level 3 matures $27 million in 2014, $60 million in periods 2015-2017, $14 million in periods 2018-2019 and $19 million in periods 2020-2030.  Risk management commodity contracts are substantially comprised of power contracts.

There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2014 and 2013.

86




The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as Level 3 in the fair value hierarchy:
Three Months Ended September 30, 2014
 
Net Risk Management
Assets (Liabilities)
 
 
(in millions)
Balance as of June 30, 2014
 
$
132

Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
(9
)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
 
10

Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
(3
)
Purchases, Issuances and Settlements (c)
 
(5
)
Transfers into Level 3 (d) (e)
 
(9
)
Transfers out of Level 3 (e) (f)
 
(1
)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
14

Balance as of September 30, 2014
 
$
129

Three Months Ended September 30, 2013
 
Net Risk Management
Assets (Liabilities)
 
 
(in millions)
Balance as of June 30, 2013
 
$
122

Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
(2
)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
 
13

Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
(3
)
Purchases, Issuances and Settlements (c)
 
(8
)
Transfers out of Level 3 (e) (f)
 
(2
)
Balance as of September 30, 2013
 
$
120

Nine Months Ended September 30, 2014
 
Net Risk Management
Assets (Liabilities)
 
 
(in millions)
Balance as of December 31, 2013
 
$
117

Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
91

Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
 
(3
)
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
12

Purchases, Issuances and Settlements (c)
 
(103
)
Transfers into Level 3 (d) (e)
 
(9
)
Transfers out of Level 3 (e) (f)
 
(8
)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
32

Balance as of September 30, 2014
 
$
129


87



Nine Months Ended September 30, 2013
 
Net Risk Management
Assets (Liabilities)
 
 
(in millions)
Balance as of December 31, 2012
 
$
86

Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
(9
)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
 
32

Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
(3
)
Purchases, Issuances and Settlements (c)
 
(7
)
Transfers into Level 3 (d) (e)
 
18

Transfers out of Level 3 (e) (f)
 
(1
)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
4

Balance as of September 30, 2013
 
$
120


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


88



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

Significant Unobservable Inputs
September 30, 2014
 
 
 
 
 
Significant
 
Input/Range
 
Fair Value
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
Technique
 
Input
 
Low
 
High
 
Average
 
(in millions)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
$
124

 
$
29

 
Discounted Cash Flow 
 
Forward Market Price (a) 
 
$
9.93

 
$
103.05

 
$
47.87

 
 
 
 

 
 
 
Counterparty Credit Risk (b) 
 
301
FTRs
35

 
1

 
Discounted Cash Flow 
 
Forward Market Price (a) 
 
(14.63
)
 
15.47

 
1.31

Total
$
159

 
$
30

 
 
 
 
 
 

 
 

 
 

Significant Unobservable Inputs
December 31, 2013
 
 
 
 
 
Significant
 
 
 
Fair Value
Valuation
 
Unobservable
 
Input/Range
 
Assets
 
Liabilities
Technique
 
Input
 
Low
 
High
 
(in millions)
 
 
 
 
 
 
 
 
Energy Contracts
$
132

 
$
22

 
Discounted Cash Flow 
 
Forward Market Price (a) 
 
$
11.42

 
$
120.72

 
 

 
 

 
 
 
Counterparty Credit Risk (b) 
 
316
FTRs
10

 
3

 
Discounted Cash Flow 
 
Forward Market Price (a) 
 
(5.10
)
 
10.44

Total
$
142

 
$
25

 
 
 
 
 
 

 
 


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

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

Sensitivity of Fair Value Measurements
September 30, 2014
Significant Unobservable Input
 
Position
 
Change in Input
 
Impact on Fair Value
Measurement
Forward Market Price
 
Buy
 
Increase (Decrease)
 
Higher (Lower)
Forward Market Price
 
Sell
 
Increase (Decrease)
 
Lower (Higher)
Counterparty Credit Risk
 
Loss
 
Increase (Decrease)
 
Higher (Lower)
Counterparty Credit Risk
 
Gain
 
Increase (Decrease)
 
Lower (Higher)



89



11.  INCOME TAXES

AEP System Tax Allocation Agreement

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

Federal and State Income Tax Audit Status

The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013.  The IRS examination of years 2011 and 2012 started in April 2014. Although the outcome of tax audits is uncertain, in our opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, we accrue interest on these uncertain tax positions.  We are not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.

We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions.  These taxing authorities routinely examine our tax returns. We are currently under examination in several state and local jurisdictions.  However, it is possible that we have filed tax returns with positions that may be challenged by these tax authorities.  We believe that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income.  We are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.



90



12.  FINANCING ACTIVITIES

Long-term Debt

The following table details long-term debt outstanding as of September 30, 2014 and December 31, 2013:
Type of Debt
 
September 30, 2014
 
December 31, 2013
 
 
(in millions)
Senior Unsecured Notes
 
$
12,017

 
$
11,799

Pollution Control Bonds
 
1,963

 
1,932

Notes Payable
 
277

 
369

Securitization Bonds
 
2,413

 
2,686

Spent Nuclear Fuel Obligation (a)
 
265

 
265

Other Long-term Debt
 
1,155

 
1,360

Fair Value of Interest Rate Hedges
 
(7
)
 
(9
)
Unamortized Discount, Net
 
(25
)
 
(25
)
Total Long-term Debt Outstanding
 
18,058

 
18,377

Long-term Debt Due Within One Year
 
2,381

 
1,549

Long-term Debt
 
$
15,677

 
$
16,828


(a)
Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal.  The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983.  Trust fund assets related to this obligation were $309 million and $309 million as of September 30, 2014 and December 31, 2013, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets.

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2014 are shown in the tables below:
Company
 
Type of Debt
 
Principal
Amount
 
Interest
Rate
 
Due Date
Issuances:
 
 
 
(in millions)
 
(%)
 
 
APCo
 
Senior Unsecured Notes
 
$
300

 
4.40
 
2044
I&M
 
Pollution Control Bonds
 
100

 
1.75
 
2018
PSO
 
Other Long-term Debt
 
75

 
Variable
 
2016
SWEPCo
 
Other Long-term Debt
 
100

 
Variable
 
2017
 
 
 
 
 
 
 
 
 
Non-Registrant:
 
 
 
 

 
 
 
 
AEPTCo
 
Senior Unsecured Notes
 
30

 
5.42
 
2044
AGR
 
Pollution Control Bonds
 
39

 
Variable
 
2015
AGR
 
Pollution Control Bonds
 
79

 
Variable
 
2015
AGR
 
Pollution Control Bonds
 
60

(a)
Variable
 
2038
KPCo
 
Pollution Control Bonds
 
65

(a)
Variable
 
2036
KPCo
 
Senior Unsecured Notes
 
120

 
4.18
 
2026
TCC
 
Senior Unsecured Notes
 
50

 
2.61
 
2019
TCC
 
Senior Unsecured Notes
 
50

 
3.81
 
2026
TCC
 
Senior Unsecured Notes
 
100

 
4.67
 
2044
Transource Missouri
 
Other Long-term Debt
 
49

 
Variable
 
2018
Total Issuances
 
 
 
$
1,217

(b)
 
 
 

(a)
Pollution Control Bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year.
(b)
Amount indicated on the statement of cash flows is net of issuance costs and premium or discount and will not tie to the issuance amount.

91



Company
 
Type of Debt
 
Principal
Amount Paid
 
Interest
Rate
 
Due Date
Total Retirements and Principal Payments:
 
 
 
(in millions)
 
(%)
 
 
APCo
 
Other Long-term Debt
 
$
300

 
Variable
 
2015
APCo
 
Securitization Bonds
 
13

 
2.01
 
2024
APCo
 
Senior Unsecured Notes
 
200

 
4.95
 
2015
I&M
 
Notes Payable
 
29

 
Variable
 
2017
I&M
 
Notes Payable
 
22

 
Variable
 
2016
I&M
 
Notes Payable
 
11

 
2.12
 
2016
I&M
 
Notes Payable
 
15

 
Variable
 
2016
I&M
 
Notes Payable
 
4

 
4.00
 
2014
I&M
 
Other Long-term Debt
 
8

 
Variable
 
2015
I&M
 
Other Long-term Debt
 
1

 
6.00
 
2025
I&M
 
Pollution Control Bonds
 
100

 
6.25
 
2014
OPCo
 
Pollution Control Bonds
 
39

 
2.875
 
2014
OPCo
 
Pollution Control Bonds
 
79

 
3.25
 
2014
OPCo
 
Pollution Control Bonds
 
60

 
3.875
 
2014
OPCo
 
Senior Unsecured Notes
 
225

 
4.85
 
2014
OPCo
 
Securitization Bonds
 
35

 
0.958
 
2018
PSO
 
Pollution Control Bonds
 
34

 
5.25
 
2014
SWEPCo
 
Notes Payable
 
3

 
4.58
 
2032
 
 
 
 
 
 
 
 
 
Non-Registrant:
 
 
 
 

 
 
 
 
AEGCo
 
Senior Unsecured Notes
 
7

 
6.33
 
2037
AEP Subsidiaries
 
Notes Payable
 
2

 
8.03
 
2026
AEP Subsidiaries
 
Notes Payable
 
1

 
7.59
 
2026
AEP Subsidiaries
 
Notes Payable
 
5

 
Variable
 
2017
KPCo
 
Other Long-term Debt
 
120

 
Variable
 
2015
TCC
 
Securitization Bonds
 
127

 
5.09
 
2015
TCC
 
Securitization Bonds
 
72

 
6.25
 
2016
TCC
 
Securitization Bonds
 
26

 
0.88
 
2017
Total Retirements and Principal Payments
 
 
 
$
1,538

 
 
 
 

In December 2013, AGR assigned KPCo $200 million of Other Long-term Debt due in May 2015. In September 2014, KPCo refinanced $120 million of the original assignment as Senior Unsecured Notes (see issuances and retirements tables above). Also in September 2014, KPCo signed an agreement to refinance the remaining $80 million in December 2014 as 4.33% Senior Unsecured Notes due in 2026. Consequently and as of September 30, 2014, the remaining $80 million was excluded from current liabilities and was instead classified as Long-term Debt on the balance sheet.

In October 2014, APCo remarketed $100 million of 1.625% Pollution Control Bonds due in 2018.

In October 2014, I&M retired $5 million of Notes Payable related to DCC Fuel.

As of September 30, 2014, trustees held on our behalf, $435 million of our reacquired Pollution Control Bonds.

Dividend Restrictions

Parent Restrictions

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

92




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

Utility Subsidiaries’ Restrictions

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

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

Short-term Debt

Our outstanding short-term debt was as follows:
 
 
September 30, 2014
 
December 31, 2013
Type of Debt
 
Outstanding
Amount
 
Interest
Rate (a)
 
Outstanding
Amount
 
Interest
Rate (a)
 
 
(in millions)
 
 

 
(in millions)
 
 

Securitized Debt for Receivables (b)
 
$
750

 
0.22
%
 
$
700

 
0.23
%
Commercial Paper
 
532

 
0.28
%
 
57

 
0.29
%
Total Short-term Debt
 
$
1,282

 
 

 
$
757

 
 


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

Credit Facilities

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

Securitized Accounts Receivable – AEP Credit

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

Our receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2016.


93



Accounts receivable information for AEP Credit is as follows:
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
 
(dollars in millions)
Effective Interest Rates on Securitization of
 

 
 

 
 

 
 

Accounts Receivable
0.21
%
 
0.23
%
 
0.22
%
 
0.23
%
Net Uncollectible Accounts Receivable
 

 
 

 
 

 
 

Written Off
$
16

 
$
12

 
$
32

 
$
26


 
September 30,
2014
 
December 31,
2013
 
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
Less Uncollectible Accounts
$
1,000

 
$
929

Total Principal Outstanding
750

 
700

Delinquent Securitized Accounts Receivable
57

 
45

Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable
13

 
16

Unbilled Receivables Related to Securitization/Sale of Accounts Receivable
269

 
331


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


94



13.  VARIABLE INTEREST ENTITIES

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

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

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the three months ended September 30, 2014 and 2013 were $41 million and $41 million, respectively, and for the nine months ended September 30, 2014 and 2013 were $121 million and $125 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on the condensed balance sheets.

I&M has nuclear fuel lease agreements with DCC Fuel II LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI LLC (collectively DCC Fuel).  DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the leases for the three months ended September 30, 2014 and 2013 were $28 million and $32 million, respectively, and for the nine months ended September 30, 2014 and 2013 were $84 million and $96 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months.  Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  In October 2013, the lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC.  See the tables below for the classification of DCC Fuel’s assets and liabilities on the condensed balance sheets.

AEP Credit is a wholly-owned subsidiary of AEP.  AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements.  AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings.  Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing.  Based on our control of AEP Credit, management concluded that we are the primary beneficiary and are required to consolidate AEP Credit.  See the tables below for the classification of AEP Credit’s assets and liabilities on the condensed balance sheets.  See “Securitized Accounts Receivable – AEP Credit” section of Note 12.


95



Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.  Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant.  Therefore, TCC is required to consolidate Transition Funding.  The securitized bonds totaled $1.8 billion and $2 billion as of September 30, 2014 and December 31, 2013, respectively.  Transition Funding has securitized transition assets of $1.7 billion and $1.9 billion as of September 30, 2014 and December 31, 2013, respectively.  The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT.  The securitization bonds are payable only from and secured by the securitized transition assets.  The bondholders have no recourse to TCC or any other AEP entity.  TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs.  See the tables below for the classification of Transition Funding’s assets and liabilities on the condensed balance sheets.

Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property.  Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant.  Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding.  The securitized bonds totaled $232 million and $267 million as of September 30, 2014 and December 31, 2013, respectively.  Ohio Phase-in-Recovery Funding has securitized assets of $116 million and $132 million as of September 30, 2014 and December 31, 2013, respectively.  The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO.  In August 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to OPCo or any other AEP entity.  OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs.  See the table below for the classification of Ohio Phase-in-Recovery Funding's assets and liabilities on the condensed balance sheets.

Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance.  Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant.  Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding.  The securitized bonds totaled $368 million and $380 million as of September 30, 2014 and December 31, 2013, respectively.  Appalachian Consumer Rate Relief Funding has securitized assets of $356 million and $369 million as of September 30, 2014 and December 31, 2013, respectively.  The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC.  In November 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to APCo or any other AEP entity.  APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs.  See the tables below for the classification of Appalachian Consumer Rate Relief Funding's assets and liabilities on the condensed balance sheets.

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

Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance.  EIS has multiple protected cells.  Neither AEP nor its subsidiaries have an equity investment in EIS.  The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance.  Our subsidiaries and any allowed

96



third parties share in the insurance coverage, premiums and risk of loss from claims.  Based on our control and the structure of the protected cell and EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate EIS.  Our insurance premium expense to the protected cell for the three months ended September 30, 2014 and 2013 were $16 million and $15 million, respectively, and for the nine months ended September 30, 2014 and 2013 were $33 million and $30 million, respectively.  See the tables below for the classification of the protected cell’s assets and liabilities on the condensed balance sheets.  The amount reported as equity is the protected cell’s policy holders’ surplus.

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

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

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
September 30, 2014
(in millions)
 
 
SWEPCo
Sabine
 
I&M
DCC Fuel
 
AEP
Credit
 
TCC
Transition
Funding
 
OPCo
Ohio
Phase-in-
Recovery
Funding
 
 
APCo
Appalachian
Consumer
Rate Relief
Funding
 
Protected
Cell
of EIS
 
Transource
Energy
ASSETS
 
 
 
 

 
 

 
 
 
 
 
 
 
 
 

 
 
Current Assets
 
$
62

 
$
69

 
$
1,006

 
$
198

 
$
22

 
 
$
10

 
$
158

 
$
3

Net Property, Plant and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equipment
 
148

 
73

 

 

 

 
 

 

 
82

Other Noncurrent Assets
 
51

 
27

 

 
1,730

(a) 
221

(b) 
 
364

(c)
3

 
4

Total Assets
 
$
261

 
$
169

 
$
1,006

 
$
1,928

 
$
243

 
 
$
374

 
$
161

 
$
89

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 

 
 
Current Liabilities
 
$
31

 
$
65

 
$
910

 
$
313

 
$
47

 
 
$
24

 
$
50

 
$
11

Noncurrent Liabilities
 
230

 
104

 

 
1,597

 
195

 
 
348

 
70

 
49

Equity
 

 

 
96

 
18

 
1

 
 
2

 
41

 
29

Total Liabilities and Equity
 
$
261

 
$
169

 
$
1,006

 
$
1,928

 
$
243

 
 
$
374

 
$
161

 
$
89


(a)
Includes an intercompany item eliminated in consolidation of $77 million.
(b)
Includes an intercompany item eliminated in consolidation of $102 million.
(c)
Includes an intercompany item eliminated in consolidation of $4 million.

97




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2013
(in millions)
 
 
SWEPCo
Sabine
 
I&M
DCC
Fuel
 
AEP
Credit
 
TCC
Transition
Funding
 
 
OPCo
Ohio
Phase-in-
Recovery
Funding
 
 
APCo
Appalachian
Consumer
Rate Relief
Funding
 
 
Protected
Cell
of EIS
ASSETS
 
 
 
 

 
 

 
 
 
 
 
 
 
 
 
 
 

Current Assets
 
$
67

 
$
118

 
$
935

 
$
232

 
 
$
23

 
 
$
6

 
 
$
143

Net Property, Plant and Equipment
 
157

 
157

 

 

 
 

 
 

 
 

Other Noncurrent Assets
 
51

 
60

 
1

 
1,918

(a) 
 
252

(b)
 
378

(c)
 
3

Total Assets
 
$
275

 
$
335

 
$
936

 
$
2,150

 
 
$
275

 
 
$
384

 
 
$
146

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 

 
 

 
 

 
 

 
 
 

 
 
 

 
 
 

Current Liabilities
 
$
33

 
$
108

 
$
827

 
$
312

 
 
$
37

 
 
$
14

 
 
$
39

Noncurrent Liabilities
 
242

 
227

 
1

 
1,820

 
 
237

 
 
368

 
 
66

Equity
 

 

 
108

 
18

 
 
1

 
 
2

 
 
41

Total Liabilities and Equity
 
$
275

 
$
335

 
$
936

 
$
2,150

 
 
$
275

 
 
$
384

 
 
$
146


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

DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and voting rights equally.  Each entity guarantees 50% of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  SWEPCo’s total billings from DHLC for the three months ended September 30, 2014 and 2013 were $24 million and $21 million, respectively, and for the nine months ended September 30, 2014 and 2013 were $31 million and $53 million, respectively.  We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC.  Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets.

Our investment in DHLC was:
 
September 30, 2014
 
December 31, 2013
 
As Reported on
the Balance Sheet
 
Maximum
Exposure
 
As Reported on
the Balance Sheet
 
Maximum
Exposure
 
(in millions)
Capital Contribution from SWEPCo
$
8

 
$
8

 
$
8

 
$
8

Retained Earnings
3

 
3

 
1

 
1

SWEPCo's Guarantee of Debt

 
113

 

 
61

 
 
 
 
 
 
 
 
Total Investment in DHLC
$
11

 
$
124

 
$
9

 
$
70


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

98




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

Our investment in PATH-WV was:
 
September 30, 2014
 
December 31, 2013
 
As Reported on
the Balance Sheet
 
Maximum
Exposure
 
As Reported on
the Balance Sheet
 
Maximum
Exposure
 
(in millions)
Capital Contribution from AEP
$
19

 
$
19

 
$
19

 
$
19

Retained Earnings
6

 
6

 
6

 
6

 
 
 
 
 
 
 
 
Total Investment in PATH-WV
$
25

 
$
25

 
$
25

 
$
25


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

99



APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

100




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

EXECUTIVE OVERVIEW

Regulatory Activity

Plant Transfer

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a cost-of-service basis. West Virginia generally allows for timely recovery of fuel costs through an expanded net energy cost which trues-up to actual expenses. In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo. In June 2014, the FERC issued an order approving AGR and WPCo's request to transfer AGR’s one-half interest in the Mitchell Plant to WPCo.

In October 2014, a stipulation agreement between APCo, WPCo, the WVPSC staff and intervenors in the case was filed with the WVPSC. The stipulation agreement recommended approval for WPCo to acquire, at net book value, the one-half interest in the Mitchell Plant, excluding $20 million of certain assets, which will be paid by WPCo and recovered as a regulatory asset over the life of the plant. Additionally, the agreement stated that 82.5% of the costs associated with the acquired interest will be reflected in rates effective from the date of the transfer via a surcharge with an offset in ENEC revenues. The remaining 17.5% of the costs associated with the acquired interest is to be included in rates by January 2020. The agreement also proposed that WPCo share the energy margins for 82.5% of the plant’s output with ratepayers and that WPCo retain all of the energy margins from sales into the wholesale market on the remaining 17.5%, to offset fixed costs associated with this portion, until the remaining portion is approved for inclusion in rates. Management anticipates an order related to the proposed plant transfer will be issued in the fourth quarter of 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “Plant Transfer” section of APCo Rate Matters in Note 4.

WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting authority to merge WPCo into APCo. In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC. In April 2013, the FERC approved the merger. Also in December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant. In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo. In December 2013, the WVPSC issued an order that deferred ruling on the merger of WPCo into APCo. The feasibility of the merger remains under review. See the “WPCo Merger with APCo” section of APCo Rate Matters in Note 4.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a biennial generation and distribution base rate case with the Virginia SCC. In accordance with a Virginia statute, APCo did not request an increase in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to the change in the expected service life of certain plants. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to IGCC and other deferred costs.


101



In August 2014, the Virginia SCC staff and intervenors filed testimony concluding that APCo's adjusted earned rate of return on common equity for 2012 and 2013, reflecting their recommended adjustments, was above the allowed threshold. Recommendations included (a) refunds to customers ranging from $15 million to $22 million, (b) the write-off of certain APCo assets, including IGCC pre-construction costs and previously approved 2009 storm costs, totaling $27 million and (c) $38 million in increased depreciation expense annually, retroactive to January 1, 2014, primarily related to accelerating depreciation on APCo generation assets to be retired in the second quarter of 2015. Hearings at the Virginia SCC were held in September 2014. A decision is expected in November 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 Virginia Biennial Base Rate Case” section of APCo Rate Matters in Note 4.

2014 West Virginia Base Rate Case

In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $156 million, based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates and requested recovery of $77 million over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $38 million annually to recover vegetation management costs, including a return on capital investment. In October 2014, the WVPSC approved APCo's motion to revise the procedural schedule which included the extension of the intervention period to November 2014 and a delay in the implementation of new rates from April 2015 to May 2015. Hearings at the WVPSC are scheduled for January 2015. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 West Virginia Base Rate Case” section of APCo Rate Matters in Note 4.

Litigation and Environmental Issues

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 170. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 249 for additional discussion of relevant factors.


102



RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions of KWhs)
Retail:
 

 
 

 
 

 
 

Residential
2,503

 
2,613

 
9,131

 
8,870

Commercial
1,726

 
1,788

 
5,150

 
5,147

Industrial
2,600

 
2,522

 
7,665

 
7,765

Miscellaneous
205

 
203

 
636

 
618

Total Retail
7,034

 
7,126

 
22,582

 
22,400

 
 
 
 
 
 
 
 
Wholesale
563

 
3,132

 
2,507

 
7,201

 
 
 
 
 
 
 
 
Total KWhs
7,597

 
10,258

 
25,089

 
29,601


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

Summary of Heating and Cooling Degree Days
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
(in degree days)
Actual - Heating (a)

 

 
1,776

 
1,497

Normal - Heating (b)
2

 
3

 
1,405

 
1,408

 
 
 
 
 
 
 
 
Actual - Cooling (c)
639

 
727

 
1,041

 
1,115

Normal - Cooling (b)
816

 
815

 
1,183

 
1,182


(a)
Eastern Region heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.


103



Third Quarter of 2014 Compared to Third Quarter of 2013
Reconciliation of Third Quarter of 2013 to Third Quarter of 2014
Net Income
(in millions)
 
Third Quarter of 2013
 
$
63

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
53

Off-system Sales
 
(3
)
Transmission Revenues
 
2

Other Revenues
 
4

Total Change in Gross Margin
 
56

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(54
)
Depreciation and Amortization
 
(16
)
Taxes Other Than Income Taxes
 
(4
)
Carrying Costs Income
 
(2
)
Other Income
 
1

Interest Expense
 
(5
)
Total Change in Expenses and Other
 
(80
)
 
 
 

Income Tax Expense
 
10

 
 
 

Third Quarter of 2014
 
$
49


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 $53 million primarily due to the following:
A $43 million increase primarily due to increases in rates in Virginia and West Virginia.  Of these increases, $32 million relate to riders/trackers which have corresponding increases in other expense items below.
A $21 million decrease in capacity settlement expenses, net of West Virginia recovery, due to the termination of the Interconnection Agreement.
These increases were partially offset by:
A $9 million decrease in weather-related usage primarily due to a 12% decrease in cooling degree days.

104



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

Other Operation and Maintenance expenses increased $54 million primarily due to the following:
An $11 million increase in transmission expenses primarily due to PJM services.
A $10 million increase in steam and electric plant maintenance expenses primarily at Amos Plant, primarily driven by APCo's increased ownership of the plant. This increase is partially offset by an increase in Retail Margins detailed above.
A $9 million increase in uncollectible accounts expense as a result of the favorable resolution of contingencies related to pole attachments in the third quarter of 2013.
A $5 million increase associated with the deferral of transmission costs in accordance with the Virginia Transmission Rate Adjustment Clause effective May 2014 as allowed by the Virginia SCC.
A $3 million increase associated with the Distribution and the Transmission Vegetation Management Programs in West Virginia in 2014.
A $2 million increase in employee-related expenses.
Depreciation and Amortization expenses increased $16 million primarily due to an increase in depreciable base including the increased ownership in Amos Plant.
Taxes Other Than Income Taxes increased $4 million primarily due to an increase in state business occupation tax and state minimum tax expense.
Interest Expense increased $5 million primarily due to the November 2013 issuance of securitization bonds and the assumption of debt related to APCo's increased ownership of Amos Plant in December 2013. This increase is partially offset by an increase in Retail Margins detailed above.
Income Tax Expense decreased $10 million primarily due to a decrease in pretax book income.


105



Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013
Reconciliation of Nine Months Ended September 30, 2013 to Nine Months Ended September 30, 2014
Net Income
(in millions)
 
Nine Months Ended September 30, 2013
 
$
163

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
168

Off-system Sales
 
(3
)
Transmission Revenues
 
3

Other Revenues
 
3

Total Change in Gross Margin
 
171

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(60
)
Depreciation and Amortization
 
(44
)
Taxes Other Than Income Taxes
 
(10
)
Carrying Costs Income
 
(7
)
Other Income
 
1

Interest Expense
 
(14
)
Total Change in Expenses and Other
 
(134
)
 
 
 

Income Tax Expense
 
(13
)
 
 
 

Nine Months Ended September 30, 2014
 
$
187


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 $168 million primarily due to the following:
A $114 million increase primarily due to increases in rates in West Virginia and Virginia.  Of these increases, $72 million relate to riders/trackers which have corresponding increases in other expense items below.
A $59 million decrease in capacity settlement expenses, net of West Virginia recovery, due to the termination of the Interconnection Agreement.
An $18 million increase in weather-related usage primarily due to a 19% increase in heating degree days.
These increases were partially offset by:
A $13 million increase in PJM expenses.


106



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

Other Operation and Maintenance expenses increased $60 million primarily due to the following:
A $27 million increase in steam operation and maintenance expenses primarily at Amos Plant, primarily driven by APCo's increased ownership of the plant. This increase is partially offset by an increase in Retail Margins detailed above.
A $21 million increase in transmission expenses due to increased investment in the PJM region.
An $18 million increase in transmission expenses primarily due to PJM services.
A $7 million increase due to the Distribution and the Transmission Vegetation Management Programs in West Virginia in 2014.
A $6 million increase in employee-related expenses.
A $5 million increase in other generation mainly due to higher miscellaneous power supply and hydro expenses.
A $4 million increase associated with the deferral of transmission costs in accordance with Virginia Transmission Rate Adjustment Clause effective May 2014 as allowed by the Virginia SCC.
A $4 million increase in uncollectible accounts expense primarily as a result of the favorable resolution of contingencies related to pole attachments in the third quarter of 2013.
These increases were partially offset by:
A $30 million write-off in the first quarter of 2013 of previously deferred Virginia storm costs resulting from the 2013 enactment of a Virginia law.
A $20 million decrease in distribution maintenance expense due to $25 million of Virginia storm expenses in January and June 2013 partially offset by $5 million of West Virginia storm expenses in June 2014.
Depreciation and Amortization expenses increased $44 million primarily due to the following:
A $32 million increase due to an increase in depreciable base including the increased ownership in Amos Plant.
A $6 million increase due to amortization of Virginia environmental deferrals. This increase in expense is offset within Retail Margins above.
Taxes Other Than Income Taxes increased $10 million primarily due to the following:
A $5 million increase in state business occupation tax and state minimum tax expense.
A $4 million increase in amortization of real and personal property taxes.
Carrying Costs Income decreased $7 million primarily due to the November 2013 securitization of the West Virginia ENEC deferral balance.
Interest Expense increased $14 million primarily due to the November 2013 issuance of securitization bonds and the assumption of debt related to APCo's increased ownership of Amos Plant in December 2013. This increase is partially offset by an increase in Retail Margins detailed above.
Income Tax Expense increased $13 million primarily due to an increase in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2013 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 249 for a discussion of accounting pronouncements.


107




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
REVENUES
 
 
 
 
 
 
 
 

Electric Generation, Transmission and Distribution
 
$
672,459

 
$
756,606

 
$
2,202,967

 
$
2,299,587

Sales to AEP Affiliates
 
35,455

 
90,558

 
108,439

 
241,311

Other Revenues
 
1,970

 
2,569

 
6,537

 
6,833

TOTAL REVENUES
 
709,884

 
849,733

 
2,317,943

 
2,547,731

 
 
 
 
 
 
 
 
 
EXPENSES
 
 

 
 

 
 

 
 

Fuel and Other Consumables Used for Electric Generation
 
194,303

 
207,442

 
627,943

 
575,902

Purchased Electricity for Resale
 
85,656

 
47,391

 
340,680

 
172,334

Purchased Electricity from AEP Affiliates
 

 
220,736

 
4,662

 
625,534

Other Operation
 
103,835

 
64,508

 
297,269

 
223,180

Maintenance
 
64,333

 
49,924

 
193,907

 
207,870

Depreciation and Amortization
 
99,889

 
84,513

 
300,125

 
255,656

Taxes Other Than Income Taxes
 
31,632

 
27,527

 
92,434

 
82,931

TOTAL EXPENSES
 
579,648

 
702,041

 
1,857,020

 
2,143,407

 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
130,236

 
147,692

 
460,923

 
404,324

 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 

 
 

 
 

 
 

Interest Income
 
521

 
334

 
1,311

 
2,134

Carrying Costs Income (Expense)
 
482

 
2,793

 
(1,130
)
 
6,029

Allowance for Equity Funds Used During Construction
 
1,665

 
826

 
4,525

 
2,809

Interest Expense
 
(52,738
)
 
(47,375
)
 
(157,540
)
 
(143,707
)
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
80,166

 
104,270

 
308,089

 
271,589

 
 
 
 
 
 
 
 
 
Income Tax Expense
 
31,408

 
41,645

 
121,233

 
108,554

 
 
 
 
 
 
 
 
 
NET INCOME
 
$
48,758

 
$
62,625

 
$
186,856

 
$
163,035

The common stock of APCo is wholly-owned by AEP.
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.



108



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
  Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
Net Income
 
$
48,758

 
$
62,625

 
$
186,856

 
$
163,035

 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
 
 

 
 

 
 

 
 

Cash Flow Hedges, Net of Tax of $92 and $12 for the Three Months Ended September 30, 2014 and 2013, Respectively, and $314 and $737 for the Nine Months Ended September 30, 2014 and 2013, Respectively
 
170

 
22

 
582

 
1,369

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $179 and $193 for the Three Months Ended September 30, 2014 and 2013, Respectively, and $538 and $579 for the Nine Months Ended September 30, 2014 and 2013, Respectively
 
(333
)
 
359

 
(999
)
 
1,075

 
 
 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
 
(163
)
 
381

 
(417
)
 
2,444

 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
$
48,595

 
$
63,006

 
$
186,439

 
$
165,479

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.



109



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2012
 
$
260,458

 
$
1,573,752

 
$
1,248,250

 
$
(29,898
)
 
$
3,052,562

 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 

 
 

 
(130,000
)
 
 

 
(130,000
)
Net Income
 
 

 
 

 
163,035

 
 

 
163,035

Other Comprehensive Income
 
 

 
 

 
 

 
2,444

 
2,444

TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2013
 
$
260,458

 
$
1,573,752

 
$
1,281,285

 
$
(27,454
)
 
$
3,088,041

 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2013
 
$
260,458

 
$
1,809,562

 
$
1,156,461

 
$
2,951

 
$
3,229,432

 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 

 
 

 
(60,000
)
 
 

 
(60,000
)
Net Income
 
 

 
 

 
186,856

 
 

 
186,856

Other Comprehensive Loss
 
 

 
 

 
 

 
(417
)
 
(417
)
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2014
 
$
260,458

 
$
1,809,562

 
$
1,283,317

 
$
2,534

 
$
3,355,871

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.




110



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2014 and December 31, 2013
(in thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2014
 
2013
CURRENT ASSETS
 
 
 
 
Cash and Cash Equivalents
 
$
2,701

 
$
2,745

Advances to Affiliates
 
70,090

 
92,485

Accounts Receivable:
 
 
 
 
Customers
 
95,688

 
142,010

Affiliated Companies
 
60,436

 
113,793

Accrued Unbilled Revenues
 
38,861

 
55,930

Miscellaneous
 
778

 
412

Allowance for Uncollectible Accounts
 
(1,945
)
 
(2,443
)
Total Accounts Receivable
 
193,818

 
309,702

Fuel
 
111,120

 
191,811

Materials and Supplies
 
130,557

 
128,843

Risk Management Assets
 
21,819

 
21,171

Regulatory Asset for Under-Recovered Fuel Costs
 
68,782

 
39,811

Prepayments and Other Current Assets
 
25,048

 
16,472

TOTAL CURRENT ASSETS
 
623,935

 
803,040

 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
Electric:
 
 
 
 
Generation
 
6,828,543

 
6,745,172

Transmission
 
2,200,241

 
2,160,660

Distribution
 
3,218,405

 
3,139,150

Other Property, Plant and Equipment
 
374,940

 
357,517

Construction Work in Progress
 
253,928

 
184,701

Total Property, Plant and Equipment
 
12,876,057

 
12,587,200

Accumulated Depreciation and Amortization
 
3,797,663

 
3,617,990

TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
9,078,394

 
8,969,210

 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
Regulatory Assets
 
1,003,018

 
1,003,890

Securitized Assets
 
355,561

 
369,355

Long-term Risk Management Assets
 
6,501

 
16,948

Deferred Charges and Other Noncurrent Assets
 
133,058

 
148,205

TOTAL OTHER NONCURRENT ASSETS
 
1,498,138

 
1,538,398

 
 
 
 
 
TOTAL ASSETS
 
$
11,200,467

 
$
11,310,648

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.



111



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
September 30, 2014 and December 31, 2013
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2014
 
2013
 
 
(in thousands)
CURRENT LIABILITIES
 
 
 
 
Accounts Payable:
 
 

 
 

General
 
$
159,067

 
$
169,184

Affiliated Companies
 
71,302

 
120,789

Long-term Debt Due Within One Year – Nonaffiliated
 
652,211

 
342,360

Long-term Debt Due Within One Year – Affiliated
 
86,000

 

Risk Management Liabilities
 
6,371

 
8,892

Customer Deposits
 
66,923

 
66,040

Deferred Income Taxes
 
40,072

 
6,899

Accrued Taxes
 
61,316

 
114,699

Accrued Interest
 
63,519

 
51,899

Regulatory Liability for Over-Recovered Fuel Costs
 
13,696

 
107,048

Other Current Liabilities
 
94,732

 
97,566

TOTAL CURRENT LIABILITIES
 
1,315,209

 
1,085,376

 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
Long-term Debt – Nonaffiliated
 
3,241,896

 
3,765,997

Long-term Debt – Affiliated
 

 
86,000

Long-term Risk Management Liabilities
 
3,293

 
10,241

Deferred Income Taxes
 
2,334,399

 
2,232,441

Regulatory Liabilities and Deferred Investment Tax Credits
 
676,480

 
631,225

Employee Benefits and Pension Obligations
 
101,613

 
82,264

Deferred Credits and Other Noncurrent Liabilities
 
171,706

 
187,672

TOTAL NONCURRENT LIABILITIES
 
6,529,387

 
6,995,840

 
 
 
 
 
TOTAL LIABILITIES
 
7,844,596

 
8,081,216

 
 
 
 
 
Rate Matters (Note 4)
 

 

Commitments and Contingencies (Note 5)
 

 

 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
Common Stock – No Par Value:
 
 
 
 
Authorized – 30,000,000 Shares
 
 

 
 
Outstanding – 13,499,500 Shares
 
260,458

 
260,458

Paid-in Capital
 
1,809,562

 
1,809,562

Retained Earnings
 
1,283,317

 
1,156,461

Accumulated Other Comprehensive Income (Loss)
 
2,534

 
2,951

TOTAL COMMON SHAREHOLDER’S EQUITY
 
3,355,871

 
3,229,432

 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
11,200,467

 
$
11,310,648

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.


112



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
OPERATING ACTIVITIES
 
 

 
 

Net Income
 
$
186,856

 
$
163,035

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 

 
 

Depreciation and Amortization
 
300,125

 
255,656

Deferred Income Taxes
 
114,778

 
89,501

Carrying Costs Income
 
1,130

 
(6,029
)
Deferral of Storm Costs
 
5,112

 
34,364

Allowance for Equity Funds Used During Construction
 
(4,525
)
 
(2,809
)
Mark-to-Market of Risk Management Contracts
 
255

 
9,409

Pension Contributions to Qualified Plan Trust
 
(8,963
)
 

Property Taxes
 
25,856

 
21,940

Fuel Over/Under-Recovery, Net
 
(114,022
)
 
46,009

Change in Other Noncurrent Assets
 
(24,290
)
 
(19,784
)
Change in Other Noncurrent Liabilities
 
29,312

 
10,199

Changes in Certain Components of Working Capital:
 
 

 
 

Accounts Receivable, Net
 
114,387

 
62,363

Fuel, Materials and Supplies
 
78,977

 
5,094

Accounts Payable
 
(65,358
)
 
(76,665
)
Accrued Taxes, Net
 
(43,092
)
 
(726
)
Other Current Assets
 
(3,748
)
 
1,970

Other Current Liabilities
 
9,085

 
(14,820
)
Net Cash Flows from Operating Activities
 
601,875

 
578,707

 
 
 
 
 
INVESTING ACTIVITIES
 
 

 
 

Construction Expenditures
 
(342,291
)
 
(272,433
)
Change in Advances to Affiliates, Net
 
22,395

 
(400
)
Other Investing Activities
 
(1,114
)
 
103

Net Cash Flows Used for Investing Activities
 
(321,010
)
 
(272,730
)
 
 
 
 
 
FINANCING ACTIVITIES
 
 

 
 

Issuance of Long-term Debt – Nonaffiliated
 
295,039

 
69,346

Change in Advances from Affiliates, Net
 

 
102,811

Retirement of Long-term Debt – Nonaffiliated
 
(512,702
)
 
(345,021
)
Principal Payments for Capital Lease Obligations
 
(4,255
)
 
(4,049
)
Dividends Paid on Common Stock
 
(60,000
)
 
(130,000
)
Other Financing Activities
 
1,009

 
1,490

Net Cash Flows Used for Financing Activities
 
(280,909
)
 
(305,423
)
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
(44
)
 
554

Cash and Cash Equivalents at Beginning of Period
 
2,745

 
3,576

Cash and Cash Equivalents at End of Period
 
$
2,701

 
$
4,130

 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 

 
 

Cash Paid for Interest, Net of Capitalized Amounts
 
$
136,919

 
$
131,600

Net Cash Paid (Received) for Income Taxes
 
22,148

 
(3,746
)
Noncash Acquisitions Under Capital Leases
 
3,451

 
3,440

Construction Expenditures Included in Current Liabilities as of September 30,
 
54,463

 
43,802

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.



113




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

The condensed notes to APCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to APCo.
 
Page
Number
 
 
Significant Accounting Matters
New Accounting Pronouncements
Comprehensive Income
Rate Matters
Commitments, Guarantees and Contingencies
Benefit Plans
Business Segments
Derivatives and Hedging
Fair Value Measurements
Income Taxes
Financing Activities
Variable Interest Entities

114





INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES

115




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

EXECUTIVE OVERVIEW

Regulatory Activity

Transmission, Distribution and Storage System Improvement Charge (TDSIC)

In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and TDSIC Plan for eligible transmission, distribution and storage system improvements. The initial estimated cost of the capital improvements and associated operation and maintenance expenses included in the TDSIC Plan of $787 million will be updated annually. The TDSIC Rider will allow the periodic adjustment of I&M's rates to provide for timely recovery of 80% of approved TDSIC Plan costs. I&M will defer the remaining 20% of approved TDSIC Plan costs to be recovered in I&M's next general rate case. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “Transmission, Distribution and Storage System Improvement Charge (TDSIC)” section of I&M Rate Matters in Note 4.
  
Litigation and Environmental Issues

In the ordinary course of business, I&M is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 170. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation

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

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 249 for additional discussion of relevant factors.


116



RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions of KWhs)
Retail:
 

 
 

 
 

 
 

Residential
1,347

 
1,487

 
4,413

 
4,365

Commercial
1,264

 
1,335

 
3,681

 
3,720

Industrial
1,933

 
1,914

 
5,701

 
5,611

Miscellaneous
15

 
16

 
50

 
51

Total Retail
4,559

 
4,752

 
13,845

 
13,747

 
 
 
 
 
 
 
 
Wholesale
3,985

 
3,198

 
13,151

 
8,029

 
 
 
 
 
 
 
 
Total KWhs
8,544

 
7,950

 
26,996

 
21,776


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

Summary of Heating and Cooling Degree Days
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
(in degree days)
Actual - Heating (a)
6

 
2

 
3,222

 
2,552

Normal - Heating (b)
11

 
11

 
2,388

 
2,396

 
 
 
 
 
 
 
 
Actual - Cooling (c)
410

 
523

 
712

 
801

Normal - Cooling (b)
581

 
584

 
843

 
846


(a)
Eastern Region heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.


117



Third Quarter of 2014 Compared to Third Quarter of 2013
Reconciliation of Third Quarter of 2013 to Third Quarter of 2014
Net Income
(in millions)
 
 
 
Third Quarter of 2013
 
$
58

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
(2
)
FERC Municipals and Cooperatives
 
(2
)
Off-system Sales
 
3

Transmission Revenues
 
1

Other Revenues
 
(10
)
Total Change in Gross Margin
 
(10
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(23
)
Depreciation and Amortization
 
(5
)
Taxes Other Than Income Taxes
 
(1
)
Interest Expense
 
1

Total Change in Expenses and Other
 
(28
)
 
 
 

Income Tax Expense
 
7

 
 
 

Third Quarter of 2014
 
$
27


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

Retail Margins decreased $2 million primarily due to the following:
An $8 million decrease due to lower Indiana recovery of energy efficiency program costs. The decrease in revenue was partially offset by a corresponding decrease in energy efficiency expense items discussed below.
A $7 million decrease in weather related usage primarily due to a 22% decrease in cooling days.
A $4 million decrease due to increased costs for power acquired under a unit power agreement.
These decreases were partially offset by:
A $9 million increase due to rate recovery primarily due to a return on assets under the Cook Plant Life Cycle Management Project rider effective January 2014.
An $8 million increase due to an Indiana Capacity Tracker Rider effective August 2014.
Margins from Off-system Sales increased $3 million due to increased sales volumes.
Other Revenues decreased $10 million primarily due to the following:
A $6 million decrease in barging. This decrease in barging is a result of River Transportation Division (RTD) no longer serving plants transferred to AGR as a result of corporate separation in Ohio. The decrease in RTD revenue was offset by a corresponding decrease in Other Operation and Maintenance expenses for barging discussed below.
A $4 million decrease due to an MPSC order disallowing 2012 to 2014 lost revenue related to Demand Side Management (DSM).


118



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

Other Operation and Maintenance expenses increased $23 million primarily due to the following:
An $8 million increase due to a third quarter 2014 accrual for expected environmental remediation costs.
A $6 million increase in maintenance of overhead lines.
A $5 million increase in nuclear expenses.
A $5 million increase in PJM expenses.
A $5 million increase in administrative and general expenses.
These increases were partially offset by:
A $5 million decrease in customer services expense related to energy efficiency. The decrease in expenses was offset by a corresponding decrease in Retail Margins discussed above.
A $5 million decrease in RTD expenses for barging activities. The decrease in RTD expenses was offset by a corresponding decrease in Other Revenues from barging activities discussed above.
Depreciation and Amortization expenses increased $5 million primarily due to higher depreciable base and a change in the life of Tanner Creek Plant.
Income Tax Expense decreased $7 million primarily due to a decrease in pretax book income partially offset by recording of federal and state income tax return adjustments in 2014.


119



Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013
Reconciliation of Nine Months Ended September 30, 2013 to Nine Months Ended September 30, 2014
Net Income
(in millions)
 
 
 
Nine Months Ended September 30, 2013
 
$
142

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
21

FERC Municipals and Cooperatives
 
(1
)
Off-system Sales
 
58

Transmission Revenues
 
10

Other Revenues
 
(26
)
Total Change in Gross Margin
 
62

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(40
)
Depreciation and Amortization
 
(18
)
Taxes Other Than Income Taxes
 
1

Other Income
 
(4
)
Total Change in Expenses and Other
 
(61
)
 
 
 

Income Tax Expense
 
(2
)
 
 
 

Nine Months Ended September 30, 2014
 
$
141


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 $21 million primarily due to the following:
A $22 million increase due to rate recovery primarily due to a return on assets under the Cook Plant Life Cycle Management Project rider effective January 2014.
A $14 million increase due to a rate increase in Indiana effective March 2013.
An $8 million increase due to an Indiana Capacity Tracker Rider effective August 2014.
An $8 million increase in weather related usage primarily due to a 26% increase in heating degree days partially offset by a decrease in cooling degree days.
These increases were partially offset by:
A $22 million decrease due to lower Indiana recovery of energy efficiency program costs. The decrease in revenue was partially offset by a corresponding decrease in energy efficiency expense items discussed below.
A $7 million decrease in certain cost recovery revenues, including fuel and PJM costs.
Margins from Off-system Sales increased $58 million due to higher market prices and increased sales volumes.
Transmission Revenues increased $10 million primarily due to increased investment in the PJM region.
Other Revenues decreased $26 million primarily due to the following:
A $22 million decrease in barging. This decrease in barging is a result of River Transportation Division (RTD) no longer serving plants transferred to AGR as a result of corporate separation in Ohio. The decrease in RTD revenue was offset by a corresponding decrease in Other Operation and Maintenance expenses for barging discussed below.
A $4 million decrease due to an MPSC order disallowing 2012 to 2014 lost revenue related to DSM.


120



Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $40 million primarily due to the following:
A $24 million increase in transmission expenses primarily due to increased PJM expenses.
A $19 million increase in nuclear expenses primarily due to a prior year deferral of $8 million in expenses, as regulatory assets, for future recovery as approved by the IURC effective March 2013 and $7 million of increased refueling amortization.
A $10 million increase in distribution expenses primarily due to metering expenses and maintenance of overhead lines.
A $10 million increase in administrative and general expenses.
An $8 million increase due to a third quarter 2014 accrual for expected environmental remediation costs.
These increases were partially offset by:
A $20 million decrease in RTD expenses for barging activities. The decrease in RTD expenses was offset by a corresponding decrease in Other Revenues from barging activities as discussed above.
A $14 million decrease in customer services expense related to energy efficiency. The decrease in expenses was offset by a corresponding decrease in Retail Margins discussed above.
Depreciation and Amortization expenses increased $18 million primarily due to higher depreciable base and a change in the life of Tanner Creek Plant.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2013 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 249 for a discussion of accounting pronouncements.

121




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
REVENUES
 
 
 
 
 
 
 
 

Electric Generation, Transmission and Distribution
 
$
520,881

 
$
537,453

 
$
1,642,721

 
$
1,518,357

Sales to AEP Affiliates
 
401

 
73,576

 
3,753

 
159,888

Other Revenues – Affiliated
 
20,832

 
27,322

 
70,821

 
89,962

Other Revenues – Nonaffiliated
 
749

 
514

 
1,298

 
3,552

TOTAL REVENUES
 
542,863

 
638,865

 
1,718,593

 
1,771,759

 
 
 
 
 
 
 
 
 
EXPENSES
 
 

 
 

 
 

 
 

Fuel and Other Consumables Used for Electric Generation
 
117,414

 
140,193

 
387,757

 
330,088

Purchased Electricity for Resale
 
20,019

 
32,976

 
52,467

 
111,602

Purchased Electricity from AEP Affiliates
 
66,561

 
116,511

 
203,807

 
317,434

Other Operation
 
144,331

 
136,702

 
431,953

 
414,418

Maintenance
 
59,043

 
43,448

 
161,854

 
139,200

Depreciation and Amortization
 
50,585

 
45,393

 
150,062

 
131,991

Taxes Other Than Income Taxes
 
22,059

 
21,278

 
64,685

 
65,899

TOTAL EXPENSES
 
480,012

 
536,501

 
1,452,585

 
1,510,632

 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
62,851

 
102,364

 
266,008

 
261,127

 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 

 
 

 
 

 
 

Interest Income
 
1,450

 
2,360

 
4,228

 
7,077

Allowance for Equity Funds Used During Construction
 
5,596

 
5,041

 
14,364

 
15,568

Interest Expense
 
(22,617
)
 
(23,932
)
 
(71,955
)
 
(72,579
)
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
47,280

 
85,833

 
212,645

 
211,193

 
 
 
 
 
 
 
 
 
Income Tax Expense
 
20,654

 
27,953

 
71,596

 
69,102

 
 
 
 
 
 
 
 
 
NET INCOME
 
$
26,626

 
$
57,880

 
$
141,049

 
$
142,091

The common stock of I&M is wholly-owned by AEP.
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.


122



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
Net Income
 
$
26,626

 
$
57,880

 
$
141,049

 
$
142,091

 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME, NET OF TAXES
 
 

 
 

 
 

 
 

Cash Flow Hedges, Net of Tax of $220 and $132 for the Three Months Ended September 30, 2014 and 2013, Respectively, and $638 and $1,986 for the Nine Months Ended September 30, 2014 and 2013, Respectively
 
410

 
244

 
1,185

 
3,688

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $22 and $94 for the Three Months Ended September 30, 2014 and 2013, Respectively, and $68 and $283 for the Nine Months Ended September 30, 2014 and 2013, Respectively
 
42

 
174

 
128

 
525

 
 
 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE INCOME
 
452

 
418

 
1,313

 
4,213

 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
$
27,078

 
$
58,298

 
$
142,362

 
$
146,304

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

123



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2012
$
56,584

 
$
980,896

 
$
795,178

 
$
(28,883
)
 
$
1,803,775

 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 

 
 

 
(47,500
)
 
 

 
(47,500
)
Net Income
 

 
 

 
142,091

 
 

 
142,091

Other Comprehensive Income
 

 
 

 
 

 
4,213

 
4,213

TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2013
$
56,584

 
$
980,896

 
$
889,769

 
$
(24,670
)
 
$
1,902,579

 
 

 
 

 
 

 
 

 
 

TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2013
$
56,584

 
$
980,896

 
$
900,182

 
$
(15,509
)
 
$
1,922,153

 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 

 
 

 
(100,000
)
 
 

 
(100,000
)
Net Income
 

 
 

 
141,049

 
 

 
141,049

Other Comprehensive Income
 

 
 

 
 

 
1,313

 
1,313

TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2014
$
56,584

 
$
980,896

 
$
941,231

 
$
(14,196
)
 
$
1,964,515

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

124



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2014 and December 31, 2013
(in thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2014
 
2013
CURRENT ASSETS
 
 
 
 
Cash and Cash Equivalents
 
$
1,418

 
$
1,317

Advances to Affiliates
 
13,499

 
55,863

Accounts Receivable:
 
 
 
 
Customers
 
40,579

 
63,011

Affiliated Companies
 
60,313

 
78,282

Accrued Unbilled Revenues
 
1,536

 
17,293

Miscellaneous
 
1,483

 
5,064

Allowance for Uncollectible Accounts
 
(91
)
 
(184
)
Total Accounts Receivable
 
103,820

 
163,466

Fuel
 
45,891

 
53,807

Materials and Supplies
 
201,692

 
209,718

Risk Management Assets
 
16,330

 
15,388

Accrued Tax Benefits
 
7,460

 
48,832

Prepayments and Other Current Assets
 
25,404

 
38,103

TOTAL CURRENT ASSETS
 
415,514

 
586,494

 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
Electric:
 
 
 
 
Generation
 
3,655,966

 
3,577,906

Transmission
 
1,332,551

 
1,304,225

Distribution
 
1,676,964

 
1,625,057

Other Property, Plant and Equipment (Including Plant to be Retired, Coal Mining and Nuclear Fuel)
 
1,441,401

 
1,421,361

Construction Work in Progress
 
561,440

 
427,164

Total Property, Plant and Equipment
 
8,668,322

 
8,355,713

Accumulated Depreciation, Depletion and Amortization
 
3,403,540

 
3,299,349

TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
5,264,782

 
5,056,364

 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
Regulatory Assets
 
513,387

 
524,114

Spent Nuclear Fuel and Decommissioning Trusts
 
2,020,248

 
1,931,610

Long-term Risk Management Assets
 
4,409

 
11,495

Deferred Charges and Other Noncurrent Assets
 
111,641

 
143,657

TOTAL OTHER NONCURRENT ASSETS
 
2,649,685

 
2,610,876

 
 
 
 
 
TOTAL ASSETS
 
$
8,329,981

 
$
8,253,734

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

125



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
September 30, 2014 and December 31, 2013
(dollars in thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2014
 
2013
CURRENT LIABILITIES
 
 
 
 
Advances from Affiliates
 
$
95,899

 
$

Accounts Payable:
 
 
 
 
General
 
146,361

 
142,219

Affiliated Companies
 
65,270

 
93,773

Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2014 and December 31, 2013 Amounts Include $64,434 and $107,143, Respectively, Related to DCC Fuel)
 
238,698

 
294,845

Risk Management Liabilities
 
3,625

 
7,029

Customer Deposits
 
34,263

 
31,103

Accrued Taxes
 
58,676

 
73,292

Accrued Interest
 
12,992

 
27,686

Obligations Under Capital Leases
 
42,500

 
46,210

Other Current Liabilities
 
167,754

 
139,088

TOTAL CURRENT LIABILITIES
 
866,038

 
855,245

 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
Long-term Debt – Nonaffiliated
 
1,710,233

 
1,744,171

Long-term Risk Management Liabilities
 
2,032

 
6,946

Deferred Income Taxes
 
1,195,401

 
1,183,350

Regulatory Liabilities and Deferred Investment Tax Credits
 
1,145,699

 
1,112,645

Asset Retirement Obligations
 
1,299,178

 
1,255,184

Deferred Credits and Other Noncurrent Liabilities
 
146,885

 
174,040

TOTAL NONCURRENT LIABILITIES
 
5,499,428

 
5,476,336

 
 
 
 
 
TOTAL LIABILITIES
 
6,365,466

 
6,331,581

 
 
 
 
 
Rate Matters (Note 4)
 

 

Commitments and Contingencies (Note 5)
 

 

 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
Common Stock – No Par Value:
 
 
 
 
Authorized – 2,500,000 Shares
 
 
 
 
Outstanding – 1,400,000 Shares
 
56,584

 
56,584

Paid-in Capital
 
980,896

 
980,896

Retained Earnings
 
941,231

 
900,182

Accumulated Other Comprehensive Income (Loss)
 
(14,196
)
 
(15,509
)
TOTAL COMMON SHAREHOLDER’S EQUITY
 
1,964,515

 
1,922,153

 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
8,329,981

 
$
8,253,734

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

126



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
OPERATING ACTIVITIES
 
 

 
 

Net Income
 
$
141,049

 
$
142,091

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 

 
 

Depreciation and Amortization
 
150,062

 
131,991

Deferred Income Taxes
 
15,792

 
84,067

Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net
 
23,951

 
(15,450
)
Allowance for Equity Funds Used During Construction
 
(14,364
)
 
(15,568
)
Mark-to-Market of Risk Management Contracts
 
(2,196
)
 
12,995

Amortization of Nuclear Fuel
 
114,238

 
101,316

Fuel Over/Under-Recovery, Net
 
18,931

 
6,459

Change in Other Noncurrent Assets
 
(36,596
)
 
(718
)
Change in Other Noncurrent Liabilities
 
66,502

 
25,249

Changes in Certain Components of Working Capital:
 
 

 
 

Accounts Receivable, Net
 
59,646

 
23,111

Fuel, Materials and Supplies
 
14,884

 
(9,859
)
Accounts Payable
 
(12,052
)
 
(35,517
)
Accrued Taxes, Net
 
30,719

 
(8,987
)
Other Current Assets
 
11,741

 
18,948

Other Current Liabilities
 
(8,201
)
 
(4,130
)
Net Cash Flows from Operating Activities
 
574,106

 
455,998

 
 
 
 
 
INVESTING ACTIVITIES
 
 

 
 

Construction Expenditures
 
(345,369
)
 
(360,668
)
Change in Advances to Affiliates, Net
 
42,364

 
(205,499
)
Purchases of Investment Securities
 
(789,461
)
 
(675,727
)
Sales of Investment Securities
 
746,272

 
635,256

Acquisitions of Nuclear Fuel
 
(109,224
)
 
(109,598
)
Insurance Proceeds Related to Cook Plant Fire
 

 
72,000

Other Investing Activities
 
11,773

 
27,888

Net Cash Flows Used for Investing Activities
 
(443,645
)
 
(616,348
)
 
 
 
 
 
FINANCING ACTIVITIES
 
 

 
 

Issuance of Long-term Debt – Nonaffiliated
 
99,323

 
348,892

Change in Advances from Affiliates, Net
 
95,899

 

Retirement of Long-term Debt – Nonaffiliated
 
(190,550
)
 
(137,544
)
Principal Payments for Capital Lease Obligations
 
(35,660
)
 
(4,112
)
Dividends Paid on Common Stock
 
(100,000
)
 
(47,500
)
Other Financing Activities
 
628

 
850

Net Cash Flows from (Used for) Financing Activities
 
(130,360
)
 
160,586

 
 
 
 
 
Net Increase in Cash and Cash Equivalents
 
101

 
236

Cash and Cash Equivalents at Beginning of Period
 
1,317

 
1,562

Cash and Cash Equivalents at End of Period
 
$
1,418

 
$
1,798

 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 

 
 

Cash Paid for Interest, Net of Capitalized Amounts
 
$
75,789

 
$
76,468

Net Cash Paid (Received) for Income Taxes
 
(1,475
)
 
(35,307
)
Noncash Acquisitions Under Capital Leases
 
5,015

 
2,858

Construction Expenditures Included in Current Liabilities as of September 30,
 
69,241

 
54,082

Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,
 
11

 
279

Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage
 
3,208

 
19

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

127




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

The condensed notes to I&M’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to I&M.
 
Page
Number
 
 
Significant Accounting Matters
New Accounting Pronouncements
Comprehensive Income
Rate Matters
Commitments, Guarantees and Contingencies
Benefit Plans
Business Segments
Derivatives and Hedging
Fair Value Measurements
Income Taxes
Financing Activities
Variable Interest Entities

128





OHIO POWER COMPANY AND SUBSIDIARIES


129




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

EXECUTIVE OVERVIEW

Company Overview

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

Regulatory Activity

Ohio Electric Security Plan Filings

2009 - 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. As of September 30, 2014, OPCo’s net deferred fuel balance was $395 million, excluding unrecognized equity carrying costs. Decisions from the Supreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs balance up to the full amount.

June 2012 - May 2015 Ohio ESP Including Capacity Charge

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

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and is $150/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50/MWh through May 2014 and is currently collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR. As of September 30, 2014, OPCo’s incurred deferred capacity costs balance was $409 million, including debt carrying costs.

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. In February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. In May and September 2014, OPCo conducted energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for the remaining 40% of the SSO load for delivery from January 2015 through May 2015. OPCo will conduct

130



energy and capacity auctions for its entire SSO load for delivery starting in June 2015. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In May 2014, an independent auditor was selected by the PUCO and an audit of the recovery of the fixed fuel costs began in June 2014. In October 2014, the independent auditor filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88 capacity charge, the independent auditor recommends a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and intends to oppose the findings in the audit report.

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

Proposed June 2015 - May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM capacity and energy auction-based generation through OPCo. The proposal also includes a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based purchase power agreement. In May 2014, intervenors and the PUCO staff filed testimony that provided various recommendations including the rejection and/or modification of various riders, including the Distribution Investment Rider and the proposed PPA. Hearings at the PUCO in the ESP case were held in June 2014. Additionally, in July 2014, OPCo submitted a separate application to continue the RSR established in the June 2012 - May 2015 ESP to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. In October 2014, OPCo filed a separate application with the PUCO to propose a new PPA for inclusion in the PPA rider, discussed above. The new PPA would include an additional 2,671 MW to be purchased from AGR over the life of the respective generating units.

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

Litigation and Environmental Issues

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 170. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 249 for additional discussion of relevant factors.

131



RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions of KWhs)
Retail:
 

 
 

 
 

 
 

Residential
3,513

 
3,742

 
11,189

 
11,006

Commercial
3,714

 
3,820

 
10,838

 
10,712

Industrial
3,647

 
4,012

 
10,822

 
12,297

Miscellaneous
26

 
29

 
88

 
91

Total Retail (a)
10,900

 
11,603

 
32,937

 
34,106

 
 
 
 
 
 
 
 
Wholesale
575

(b)
4,222

 
1,727

(b)
9,683

 
 
 
 
 
 
 
 
Total KWhs
11,475

 
15,825

 
34,664

 
43,789


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

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

Summary of Heating and Cooling Degree Days
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
 
 
(in degree days)
Actual - Heating (a)
 
1

 
1

 
2,540

 
2,165

Normal - Heating (b)
 
7

 
8

 
2,074

 
2,083

 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
581

 
646

 
943

 
991

Normal - Cooling (b)
 
663

 
660

 
946

 
940


(a)
Eastern Region heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.

132




Third Quarter of 2014 Compared to Third Quarter of 2013
Reconciliation of Third Quarter of 2013 to Third Quarter of 2014
Net Income
(in millions)
 
 
 
Third Quarter of 2013
 
$
179

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
(256
)
Off-system Sales
 
(39
)
Transmission Revenues
 
10

Other Revenues
 
(11
)
Total Change in Gross Margin
 
(296
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
33

Depreciation and Amortization
 
40

Taxes Other Than Income Taxes
 
16

Other Income
 
1

Carrying Costs Income
 
3

Interest Expense
 
14

Total Change in Expenses and Other
 
107

 
 
 

Income Tax Expense
 
64

 
 
 

Third Quarter of 2014
 
$
54


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

Retail Margins decreased $256 million primarily due to the following:
A $229 million decrease due to the impacts of corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013 and regulatory provisions. In addition, this decrease includes customers switching to alternative CRES providers, which is partially offset by an increase in Transmission Revenues detailed below.
These decreases were partially offset by:
A $17 million increase in revenues primarily associated with the Distribution Investment Rider and Universal Service Fund (USF) surcharge. Of these increases, including the USF, $6 million relates to riders/trackers which have corresponding increases in other expense items below.
A $14 million increase in revenues associated with the Storm Damage Recovery Rider. This increase in Retail Margins is primarily offset by an increase in Other Operation and Maintenance below.
Margins from Off-system Sales decreased $39 million due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
Transmission Revenues increased $10 million primarily due to increased transmission revenues due to customers who have switched to alternative CRES providers, rate increases for customers in the PJM region and increased transmission investment.  The increase in transmission revenues related to CRES providers primarily offsets lost revenues included in Retail Margins above.
Other Revenues decreased $11 million primarily due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.


133



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

Other Operation and Maintenance expenses decreased $33 million primarily due to the following:
An $82 million decrease due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
This decrease was partially offset by:
A $36 million increase in PJM expenses. This increase was partially offset by a corresponding increase in Gross Margin above.
A $13 million increase due to the amortization of 2012 deferred storm expenses. This increase was offset by a corresponding increase in Retail Margins above.
Depreciation and Amortization expenses decreased $40 million primarily due to the following:
A $53 million decrease due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
This decrease was partially offset by:
A $9 million increase in amortization of securitized assets being recovered through the Deferred Asset Phase-In Rider. This increase was offset by a corresponding increase in Retail Margins above.
Taxes Other Than Income Taxes decreased $16 million primarily due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
Interest Expense decreased $14 million primarily due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
Income Tax Expense decreased $64 million primarily due to a decrease in pretax book income.


134



Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013
Reconciliation of Nine Months Ended September 30, 2013 to Nine Months Ended September 30, 2014
Net Income
(In Millions)
 
 
 
Nine Months Ended September 30, 2013
 
$
330

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
(684
)
Off-system Sales
 
(94
)
Transmission Revenues
 
60

Other Revenues
 
(34
)
Total Change in Gross Margin
 
(752
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
135

Asset Impairments and Other Related Charges
 
154

Depreciation and Amortization
 
124

Taxes Other Than Income Taxes
 
42

Other Income
 
6

Carrying Costs Income
 
10

Interest Expense
 
46

Total Change in Expenses and Other
 
517

 
 
 

Income Tax Expense
 
76

 
 
 

Nine Months Ended September 30, 2014
 
$
171


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

Retail Margins decreased $684 million primarily due to the following:
A $621 million decrease due to the impacts of corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013 and regulatory provisions. In addition, this decrease includes customers switching to alternative CRES providers, which is partially offset by an increase in Transmission Revenues detailed below.
These decreases were partially offset by:
A $45 million increase in revenues primarily associated with the Distribution Investment Rider and Universal Service Fund (USF) surcharge. Of these increases, including the USF, $18 million relates to riders/trackers which have corresponding increases in other expense items below.
A $28 million increase in revenues associated with the Storm Damage Recovery Rider. This increase in Retail Margins is primarily offset by an increase in Other Operation and Maintenance expenses below.
Margins from Off-system Sales decreased $94 million due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
Transmission Revenues increased $60 million primarily due to increased transmission revenues due to customers who have switched to alternative CRES providers, rate increases for customers in the PJM region and increased transmission investment.  The increase in transmission revenues related to CRES providers primarily offsets lost revenues included in Retail Margins above.
Other Revenues decreased $34 million due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013. This decrease in Other Revenues has a corresponding decrease in Other Operation and Maintenance expenses below.

135




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

Other Operation and Maintenance expenses decreased $135 million primarily due to the following:
A $291 million decrease due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
This decrease was partially offset by:
A $90 million increase in PJM expenses. This increase was partially offset by a corresponding increase in Gross Margin above.
A $26 million increase due to the amortization of 2012 deferred storm expenses. This increase was offset by a corresponding increase in Retail Margins above.
A $14 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins above.
Asset Impairments and Other Related Charges decreased $154 million primarily due to the 2013 impairment of Muskingum River Plant, Unit 5.
Depreciation and Amortization expenses decreased $124 million primarily due to the following:
A $154 million decrease due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
This decrease was partially offset by:
A $19 million increase in amortization of securitized assets being recovered through the Deferred Asset Phase-In Rider. This increase was offset by a corresponding increase in Retail Margins above.
An $8 million increase due to an increase in depreciable base of transmission and distribution assets.
Taxes Other Than Income Taxes decreased $42 million due to the following:
A $51 million decrease due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
This decrease was partially offset by:
A $7 million increase in property taxes due to increased investment in transmission and distribution assets and increased tax rates.
Other Income increased $6 million due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
Carrying Costs Income increased $10 million primarily due to increased capacity deferral carrying charges.
Interest Expense decreased $46 million primarily due to corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013.
Income Tax Expense decreased $76 million primarily due to a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2013 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 249 for a discussion of accounting pronouncements.


136





OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
REVENUES
 
 
 
 
 
 
 
 

Electric Generation, Transmission and Distribution
 
$
793,900

 
$
959,816

 
$
2,380,768

 
$
2,710,990

Sales to AEP Affiliates
 
43,733

 
313,818

 
120,154

 
873,850

Other Revenues – Affiliated
 

 
2,715

 

 
18,138

Other Revenues – Nonaffiliated
 
1,564

 
2,827

 
4,628

 
12,982

TOTAL REVENUES
 
839,197

 
1,279,176

 
2,505,550

 
3,615,960

 
 
 
 
 
 
 
 
 
EXPENSES
 
 

 
 

 
 

 
 

Fuel and Other Consumables Used for Electric Generation
 

 
396,437

 

 
1,158,389

Purchased Electricity for Resale
 
48,541

 
34,568

 
191,730

 
114,911

Purchased Electricity from AEP Affiliates
 
315,903

 
103,869

 
897,658

 
257,540

Amortization of Generation Deferrals
 
26,655

 

 
82,818

 

Other Operation
 
145,163

 
159,965

 
428,074

 
481,417

Maintenance
 
53,724

 
71,670

 
136,965

 
218,962

Asset Impairments and Other Related Charges
 

 

 

 
154,304

Depreciation and Amortization
 
54,968

 
94,802

 
165,152

 
289,472

Taxes Other Than Income Taxes
 
89,564

 
105,070

 
268,734

 
310,285

TOTAL EXPENSES
 
734,518

 
966,381

 
2,171,131

 
2,985,280

 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
104,679

 
312,795

 
334,419

 
630,680

 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 

 
 

 
 

 
 

Interest Income
 
1,986

 
476

 
8,159

 
3,165

Carrying Costs Income
 
5,606

 
2,813

 
19,594

 
9,833

Allowance for Equity Funds Used During Construction
 
1,825

 
1,028

 
4,893

 
2,853

Interest Expense
 
(31,171
)
 
(45,070
)
 
(96,937
)
 
(142,487
)
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
82,925

 
272,042

 
270,128

 
504,044

 
 
 
 
 
 
 
 
 
Income Tax Expense
 
28,865

 
93,141

 
98,759

 
174,313

 
 
 
 
 
 
 
 
 
NET INCOME
 
$
54,060

 
$
178,901

 
$
171,369

 
$
329,731

The common stock of OPCo is wholly-owned by AEP.
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.


137



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
Net Income
 
$
54,060

 
$
178,901

 
$
171,369

 
$
329,731

 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $185 and $363 for the Three Months Ended September 30, 2014 and 2013, Respectively, and $611 and $83 for the Nine Months Ended September 30, 2014 and 2013, Respectively
 
(343
)
 
(675
)
 
(1,134
)
 
(154
)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,607 and $5,128 for the Three and Nine Months Ended in 2013, Respectively
 

 
2,985

 

 
9,524

 
 
 

 
 

 
 

 
 

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
 
(343
)
 
2,310

 
(1,134
)
 
9,370

 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
$
53,717

 
$
181,211

 
$
170,235

 
$
339,101

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.


138



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2012
$
321,201

 
$
1,744,099

 
$
2,626,134

 
$
(165,725
)
 
$
4,525,709

 
 
 
 
 
 
 
 
 
 
Distribution of Cook Coal Terminal to Parent
 
 
 
 
(22,303
)
 
19,652

 
(2,651
)
Common Stock Dividends
 

 
 

 
(275,000
)
 
 

 
(275,000
)
Net Income
 

 
 

 
329,731

 
 

 
329,731

Other Comprehensive Income
 

 
 

 
 

 
9,370

 
9,370

TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2013
$
321,201

 
$
1,744,099

 
$
2,658,562

 
$
(136,703
)
 
$
4,587,159

 
 

 
 

 
 

 
 

 
 

TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2013
$
321,201

 
$
663,782

 
$
633,203

 
$
7,079

 
$
1,625,265

 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 

 
 

 
(35,000
)
 
 

 
(35,000
)
Net Income
 

 
 

 
171,369

 
 

 
171,369

Other Comprehensive Loss
 

 
 

 
 

 
(1,134
)
 
(1,134
)
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2014
$
321,201

 
$
663,782

 
$
769,572

 
$
5,945

 
$
1,760,500

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.
 


139



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2014 and December 31, 2013
(in thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2014
 
2013
CURRENT ASSETS
 
 
 
 
Cash and Cash Equivalents
 
$
3,889

 
$
3,004

Restricted Cash for Securitized Funding
 
17,734

 
19,387

Advances to Affiliates
 
23,745

 
339,070

Accounts Receivable:
 
 
 
 
Customers
 
47,423

 
67,054

Affiliated Companies
 
85,462

 
74,771

Accrued Unbilled Revenues
 
31,181

 
36,353

Miscellaneous
 
959

 
1,559

Allowance for Uncollectible Accounts
 
(179
)
 
(34,984
)
Total Accounts Receivable
 
164,846

 
144,753

Notes Receivable Due Within One Year – Affiliated
 
86,000

 
178,580

Materials and Supplies
 
54,958

 
53,711

Risk Management Assets
 
7,917

 
3,082

Deferred Income Tax Benefits
 
19,387

 
36,105

Accrued Tax Benefits
 
1,888

 
7,109

Prepayments and Other Current Assets
 
6,449

 
22,312

TOTAL CURRENT ASSETS
 
386,813

 
807,113

 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
Electric:
 
 
 
 
Transmission
 
2,064,599

 
2,011,289

Distribution
 
3,995,070

 
3,877,532

Other Property, Plant and Equipment
 
389,392

 
364,573

Construction Work in Progress
 
238,195

 
185,428

Total Property, Plant and Equipment
 
6,687,256

 
6,438,822

Accumulated Depreciation and Amortization
 
2,011,530

 
1,973,042

TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
4,675,726

 
4,465,780

 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
Notes Receivable – Affiliated
 
32,245

 
118,245

Regulatory Assets
 
1,370,561

 
1,378,697

Securitized Assets
 
115,806

 
131,582

Long-term Risk Management Assets
 
5

 

Deferred Charges and Other Noncurrent Assets
 
113,477

 
260,141

TOTAL OTHER NONCURRENT ASSETS
 
1,632,094

 
1,888,665

 
 
 
 
 
TOTAL ASSETS
 
$
6,694,633

 
$
7,161,558

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.


140



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
September 30, 2014 and December 31, 2013
(dollars in thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2014
 
2013
CURRENT LIABILITIES
 
 
 
 
Accounts Payable:
 
 

 
 

General
 
$
128,400

 
$
146,307

Affiliated Companies
 
142,052

 
222,889

Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2014 and December 31, 2013 Amounts Include $45,427 and $34,936, Respectively, Related to Ohio Phase-in-Recovery Funding)
 
131,496

 
438,595

Customer Deposits
 
52,113

 
49,140

Accrued Taxes
 
238,481

 
429,260

Accrued Interest
 
45,895

 
40,853

Other Current Liabilities
 
143,091

 
95,194

TOTAL CURRENT LIABILITIES
 
881,528

 
1,422,238

 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
Long-term Debt – Nonaffiliated
(September 30, 2014 and December 31, 2013 Amounts Include $187,040 and $232,466, Respectively, Related to Ohio Phase-in-Recovery Funding)
 
2,165,508

 
2,296,580

Deferred Income Taxes
 
1,357,930

 
1,330,711

Regulatory Liabilities and Deferred Investment Tax Credits
 
479,704

 
435,499

Employee Benefits and Pension Obligations
 
23,958

 
28,329

Deferred Credits and Other Noncurrent Liabilities
 
25,505

 
22,936

TOTAL NONCURRENT LIABILITIES
 
4,052,605

 
4,114,055

 
 
 
 
 
TOTAL LIABILITIES
 
4,934,133

 
5,536,293

 
 
 
 
 
Rate Matters (Note 4)
 

 

Commitments and Contingencies (Note 5)
 

 

 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
Common Stock – No Par Value:
 
 
 
 
Authorized – 40,000,000 Shares
 
 

 
 
Outstanding – 27,952,473 Shares
 
321,201

 
321,201

Paid-in Capital
 
663,782

 
663,782

Retained Earnings
 
769,572

 
633,203

Accumulated Other Comprehensive Income (Loss)
 
5,945

 
7,079

TOTAL COMMON SHAREHOLDER’S EQUITY
 
1,760,500

 
1,625,265

 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
6,694,633

 
$
7,161,558

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.


141



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
OPERATING ACTIVITIES
 
 

 
 

Net Income
 
$
171,369

 
$
329,731

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 

 
 

Depreciation and Amortization
 
165,152

 
289,472

Amortization of Generation Deferrals
 
82,818

 

Deferred Income Taxes
 
27,990

 
111,850

Asset Impairments and Other Related Charges
 

 
154,304

Carrying Costs Income
 
(19,594
)
 
(9,833
)
Allowance for Equity Funds Used During Construction
 
(4,893
)
 
(2,853
)
Mark-to-Market of Risk Management Contracts
 
(5,003
)
 
14,037

Pension Contributions to Qualified Plan Trust
 
(6,547
)
 

Property Taxes
 
148,124

 
166,607

Fuel Over/Under-Recovery, Net
 
37,326

 
21,271

Deferral of Ohio Capacity Costs, Net
 
(138,737
)
 
(156,952
)
Change in Other Noncurrent Assets
 
35,962

 
(29,012
)
Change in Other Noncurrent Liabilities
 
59,081

 
(11,664
)
Changes in Certain Components of Working Capital:
 
 

 
 

Accounts Receivable, Net
 
(20,395
)
 
123,893

Fuel, Materials and Supplies
 
(1,247
)
 
79,028

Accounts Payable
 
(83,029
)
 
(67,487
)
Customer Deposits
 
2,973

 
(2,275
)
Accrued Taxes, Net
 
(173,470
)
 
(187,677
)
Other Current Assets
 
(947
)
 
3,246

Other Current Liabilities
 
26,039

 
(36,976
)
Net Cash Flows from Operating Activities
 
302,972

 
788,710

 
 
 
 
 
INVESTING ACTIVITIES
 
 

 
 

Construction Expenditures
 
(327,972
)
 
(445,189
)
Change in Restricted Cash for Securitized Funding
 
1,653

 

Change in Advances to Affiliates, Net
 
315,325

 
101,616

Proceeds from Sales of Assets
 
886

 
13,059

Proceeds from Notes Receivable  Affiliated
 
178,580

 

Other Investing Activities
 
5,921

 
(8,586
)
Net Cash Flows from (Used for) Investing Activities
 
174,393

 
(339,100
)
 
 
 
 
 
FINANCING ACTIVITIES
 
 

 
 

Issuance of Long-term Debt – Nonaffiliated
 

 
977,002

Issuance of Long-term Debt – Affiliated
 

 
200,000

Change in Advances from Affiliates, Net
 

 
1,063

Retirement of Long-term Debt – Nonaffiliated
 
(438,583
)
 
(1,146,000
)
Retirement of Long-term Debt – Affiliated
 

 
(200,000
)
Principal Payments for Capital Lease Obligations
 
(3,912
)
 
(7,920
)
Dividends Paid on Common Stock
 
(35,000
)
 
(275,000
)
Other Financing Activities
 
1,015

 
1,946

Net Cash Flows Used for Financing Activities
 
(476,480
)
 
(448,909
)
 
 
 
 
 
Net Increase in Cash and Cash Equivalents
 
885

 
701

Cash and Cash Equivalents at Beginning of Period
 
3,004

 
3,640

Cash and Cash Equivalents at End of Period
 
$
3,889

 
$
4,341

 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 

 
 

Cash Paid for Interest, Net of Capitalized Amounts
 
$
90,188

 
$
145,817

Net Cash Paid for Income Taxes
 
15,523

 
38,446

Noncash Acquisitions Under Capital Leases
 
4,505

 
5,756

Government Grants Included in Accounts Receivable as of September 30,
 

 
377

Construction Expenditures Included in Current Liabilities as of September 30,
 
45,691

 
68,481

Noncash Distribution of Cook Coal Terminal to Parent
 

 
(22,303
)
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.


142




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

The condensed notes to OPCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to OPCo.
 
Page
Number
 
 
Significant Accounting Matters
New Accounting Pronouncements
Comprehensive Income
Rate Matters
Commitments, Guarantees and Contingencies
Disposition and Impairments
Benefit Plans
Business Segments
Derivatives and Hedging
Fair Value Measurements
Income Taxes
Financing Activities
Variable Interest Entities




143





PUBLIC SERVICE COMPANY OF OKLAHOMA

144




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

EXECUTIVE OVERVIEW

Regulatory Activity

2014 Oklahoma Base Rate Case

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

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

Litigation and Environmental Issues

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 170. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 249 for additional discussion of relevant factors.


145



RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions of KWhs)
Retail:
 

 
 

 
 

 
 

Residential
1,981

 
2,100

 
4,978

 
4,906

Commercial
1,455

 
1,475

 
3,905

 
3,829

Industrial
1,407

 
1,344

 
3,939

 
3,829

Miscellaneous
356

 
353

 
956

 
951

Total Retail
5,199

 
5,272

 
13,778

 
13,515

 
 
 
 
 
 
 
 
Wholesale
42

 
330

 
318

 
852

 
 
 
 
 
 
 
 
Total KWhs
5,241

 
5,602

 
14,096

 
14,367


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

Summary of Heating and Cooling Degree Days
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
(in degree days)
Actual - Heating (a)

 

 
1,417

 
1,208

Normal - Heating (b)
1

 
2

 
1,086

 
1,084

 
 
 
 
 
 
 
 
Actual - Cooling (c)
1,259

 
1,357

 
1,935

 
2,006

Normal - Cooling (b)
1,394

 
1,395

 
2,058

 
2,059


(a)
Western Region heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Western Region cooling degree days are calculated on a 65 degree temperature base.

146




Third Quarter of 2014 Compared to Third Quarter of 2013
Reconciliation of Third Quarter of 2013 to Third Quarter of 2014
Net Income
(in millions)
 
 
 
Third Quarter of 2013
 
$
51

 
 
 
Changes in Gross Margin:
 
 
Retail Margins (a)
 
1

Other Revenues
 
(3
)
Total Change in Gross Margin
 
(2
)
 
 
 
Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(8
)
Taxes Other Than Income Taxes
 
2

Other Income
 
(1
)
Total Change in Expenses and Other
 
(7
)
 
 
 

Income Tax Expense
 
3

 
 
 

Third Quarter of 2014
 
$
45


(a)
Includes firm wholesale sales to municipals and cooperatives.

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

Retail Margins increased $1 million primarily due to the following:
A $5 million increase primarily due to revenue increases from rate riders. This increase in retail margins has corresponding increases to riders/trackers recognized in other expense items below.
This increase was partially offset by:
A $5 million decrease in weather-related usage primarily due to a 7% decrease in cooling degree days.
Other Revenues decreased $3 million primarily due a 2013 sale of fuel inventory.

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

Other Operation and Maintenance expenses increased $8 million primarily due to the following:
A $5 million increase in general and administrative expenses.
A $4 million increase in transmission expenses primarily due to increased SPP transmission services.
A $3 million increase in energy efficiency program expenses.
These increases were partially offset by:
A $3 million decrease in distribution expenses primarily related to the amortization of the 2007 and 2010 storm deferrals which were fully recovered in 2013.
Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income.

147




Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013
Reconciliation of Nine Months Ended September 30, 2013 to Nine Months Ended September 30, 2014
Net Income
(in millions)
 
 
 
Nine Months Ended September 30, 2013
 
$
93

 
 
 

Changes in Gross Margin:
 
 

Retail Margins (a)
 
1

Off-system Sales
 
1

Other Revenues
 
(4
)
Total Change in Gross Margin
 
(2
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(29
)
Depreciation and Amortization
 
(1
)
Taxes Other Than Income Taxes
 
6

Other Income
 
(2
)
Interest Expense
 
(1
)
Total Change in Expenses and Other
 
(27
)
 
 
 

Income Tax Expense
 
12

 
 
 

Nine Months Ended September 30, 2014
 
$
76


(a)
Includes firm wholesale sales to municipals and cooperatives.

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

Retail Margins increased $1 million primarily due to the following:
A $3 million increase primarily due to revenue increases from rate riders. This increase in retail margins has corresponding increases to riders/trackers recognized in other expense items below.
This increase was partially offset by:
A $3 million net decrease in weather-related usage primarily due to a 4% decrease in cooling degree days, partially offset by an increase in heating degree.
Other Revenues decreased $4 million primarily due a 2013 sale of fuel inventory.

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

Other Operation and Maintenance expenses increased $29 million primarily due to the following:
A $16 million increase in transmission expenses primarily due to increased SPP transmission services.
A $10 million increase in generation plant operation and maintenance expenses.
A $5 million increase in general and administrative expenses.
A $5 million increase in energy efficiency program expenses.
These increases were partially offset by:
A $9 million decrease in distribution expenses primarily related to amortization of the 2007 and 2010 storm deferrals which were fully recovered in 2013.
Taxes Other Than Income Taxes decreased $6 million primarily due to a 2014 property tax reduction resulting from a change in Oklahoma tax law.
Income Tax Expense decreased $12 million primarily due to a decrease in pretax book income.


148



CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2013 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 249 for a discussion of accounting pronouncements.


149




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
REVENUES
 
 
 
 
 
 
 
 

Electric Generation, Transmission and Distribution
 
$
415,193

 
$
408,803

 
$
1,028,427

 
$
986,008

Sales to AEP Affiliates
 
789

 
1,659

 
6,240

 
9,186

Other Revenues
 
1,009

 
621

 
2,524

 
2,865

TOTAL REVENUES
 
416,991

 
411,083

 
1,037,191

 
998,059

 
 
 
 
 
 
 
 
 
EXPENSES
 
 

 
 

 
 

 
 

Fuel and Other Consumables Used for Electric Generation
 
85,018

 
124,763

 
192,567

 
254,314

Purchased Electricity for Resale
 
117,521

 
55,915

 
301,816

 
179,405

Purchased Electricity from AEP Affiliates
 

 
13,129

 
11,024

 
30,168

Other Operation
 
71,605

 
60,566

 
193,101

 
162,032

Maintenance
 
21,800

 
25,071

 
76,223

 
78,396

Depreciation and Amortization
 
24,496

 
24,191

 
73,085

 
72,449

Taxes Other Than Income Taxes
 
9,137

 
11,616

 
27,757

 
33,440

TOTAL EXPENSES
 
329,577

 
315,251

 
875,573

 
810,204

 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
87,414

 
95,832

 
161,618

 
187,855

 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 

 
 

 
 

 
 

Interest Income
 
137

 
25

 
138

 
1,146

Carrying Costs Income
 

 
21

 

 
338

Allowance for Equity Funds Used During Construction
 
194

 
852

 
2,215

 
2,676

Interest Expense
 
(13,913
)
 
(13,417
)
 
(41,009
)
 
(40,016
)
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
73,832

 
83,313

 
122,962

 
151,999

 
 
 
 
 
 
 
 
 
Income Tax Expense
 
28,746

 
32,217

 
46,979

 
58,778

 
 
 
 
 
 
 
 
 
NET INCOME
 
$
45,086

 
$
51,096

 
$
75,983

 
$
93,221

The common stock of PSO is wholly-owned by AEP.
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

150



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
Net Income
 
$
45,086

 
$
51,096

 
$
75,983

 
$
93,221

 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE LOSS, NET OF TAXES
 
 

 
 

 
 

 
 

Cash Flow Hedges, Net of Tax of $102 and $92 for the Three Months Ended September 30, 2014 and 2013, Respectively, and $337 and $319 for the Nine Months Ended September 30, 2014 and 2013, Respectively
 
(190
)
 
(172
)
 
(626
)
 
(593
)
 
 
 

 
 

 
 

 
 

TOTAL COMPREHENSIVE INCOME
 
$
44,896

 
$
50,924

 
$
75,357

 
$
92,628

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

151



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
EQUITY - DECEMBER 31, 2012
$
157,230

 
$
364,037

 
$
388,530

 
$
6,481

 
$
916,278

 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 

 
 

 
(41,250
)
 
 

 
(41,250
)
Net Income
 

 
 

 
93,221

 
 

 
93,221

Other Comprehensive Loss
 

 
 

 
 

 
(593
)
 
(593
)
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
EQUITY - SEPTEMBER 30, 2013
$
157,230

 
$
364,037

 
$
440,501

 
$
5,888

 
$
967,656

 
 

 
 

 
 

 
 

 
 

TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
EQUITY - DECEMBER 31, 2013
$
157,230

 
$
364,037

 
$
415,076

 
$
5,758

 
$
942,101

 
 
 
 
 
 
 
 
 
 
Net Income
 

 
 

 
75,983

 
 

 
75,983

Other Comprehensive Loss
 

 
 

 
 

 
(626
)
 
(626
)
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
EQUITY - SEPTEMBER 30, 2014
$
157,230

 
$
364,037

 
$
491,059

 
$
5,132

 
$
1,017,458

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.


152



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2014 and December 31, 2013
(in thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2014
 
2013
CURRENT ASSETS
 
 
 
 
Cash and Cash Equivalents
 
$
1,828

 
$
1,277

Accounts Receivable:
 
 
 
 
Customers
 
32,464

 
32,314

Affiliated Companies
 
26,770

 
30,392

Miscellaneous
 
5,907

 
3,102

Allowance for Uncollectible Accounts
 
(128
)
 
(462
)
Total Accounts Receivable
 
65,013

 
65,346

Fuel
 
10,524

 
15,191

Materials and Supplies
 
51,619

 
52,707

Risk Management Assets
 
563

 
1,167

Deferred Income Tax Benefits
 

 
7,333

Accrued Tax Benefits
 
12,298

 
21,665

Regulatory Asset for Under-Recovered Fuel Costs
 
36,544

 
3,298

Prepayments and Other Current Assets
 
9,226

 
6,194

TOTAL CURRENT ASSETS
 
187,615

 
174,178

 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
Electric:
 
 
 
 
Generation
 
1,248,341

 
1,203,221

Transmission
 
770,613

 
731,312

Distribution
 
2,062,942

 
1,986,032

Other Property, Plant and Equipment (Including Plant to be Retired)
 
426,221

 
393,026

Construction Work in Progress
 
158,716

 
175,890

Total Property, Plant and Equipment
 
4,666,833

 
4,489,481

Accumulated Depreciation and Amortization
 
1,333,626

 
1,323,522

TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
3,333,207

 
3,165,959

 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
Regulatory Assets
 
143,123

 
156,690

Long-term Risk Management Assets
 
3

 

Employee Benefits and Pension Assets
 
27,272

 
22,629

Deferred Charges and Other Noncurrent Assets
 
15,184

 
7,238

TOTAL OTHER NONCURRENT ASSETS
 
185,582

 
186,557

 
 
 
 
 
TOTAL ASSETS
 
$
3,706,404

 
$
3,526,694

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

153



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
September 30, 2014 and December 31, 2013
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2014
 
2013
 
 
(in thousands)
CURRENT LIABILITIES
 
 
 
 
Advances from Affiliates
 
$
100,867

 
$
36,772

Accounts Payable:
 
 

 
 

General
 
98,911

 
150,184

Affiliated Companies
 
40,599

 
45,427

Long-term Debt Due Within One Year – Nonaffiliated
 
424

 
34,115

Risk Management Liabilities
 

 
85

Customer Deposits
 
48,126

 
45,379

Accrued Taxes
 
45,850

 
23,442

Accrued Interest
 
14,904

 
12,646

Other Current Liabilities
 
50,342

 
58,992

TOTAL CURRENT LIABILITIES
 
400,023

 
407,042

 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
Long-term Debt – Nonaffiliated
 
1,040,632

 
965,695

Deferred Income Taxes
 
853,893

 
836,556

Regulatory Liabilities and Deferred Investment Tax Credits
 
326,048

 
327,673

Employee Benefits and Pension Obligations
 
10,772

 
10,561

Deferred Credits and Other Noncurrent Liabilities
 
57,578

 
37,066

TOTAL NONCURRENT LIABILITIES
 
2,288,923

 
2,177,551

 
 
 
 
 
TOTAL LIABILITIES
 
2,688,946

 
2,584,593

 
 
 
 
 
Rate Matters (Note 4)
 

 

Commitments and Contingencies (Note 5)
 

 

 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
Common Stock – Par Value – $15 Per Share:
 
 
 
 
Authorized – 11,000,000 Shares
 
 

 
 
Issued – 10,482,000 Shares
 
 

 
 
Outstanding – 9,013,000 Shares
 
157,230

 
157,230

Paid-in Capital
 
364,037

 
364,037

Retained Earnings
 
491,059

 
415,076

Accumulated Other Comprehensive Income (Loss)
 
5,132

 
5,758

TOTAL COMMON SHAREHOLDER’S EQUITY
 
1,017,458

 
942,101

 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
3,706,404

 
$
3,526,694

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

154



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
OPERATING ACTIVITIES
 
 

 
 

Net Income
 
$
75,983

 
$
93,221

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 

 
 

Depreciation and Amortization
 
73,085

 
72,449

Deferred Income Taxes
 
27,327

 
39,665

Allowance for Equity Funds Used During Construction
 
(2,215
)
 
(2,676
)
Mark-to-Market of Risk Management Contracts
 
432

 
(4,984
)
Pension Contributions to Qualified Plan Trust
 
(4,439
)
 

Property Taxes
 
(7,970
)
 
(10,177
)
Fuel Over/Under-Recovery, Net
 
(33,246
)
 
(9,201
)
Change in Other Noncurrent Assets
 
2,035

 
(3,513
)
Change in Other Noncurrent Liabilities
 
(2,015
)
 
(13,094
)
Changes in Certain Components of Working Capital:
 
 

 
 

Accounts Receivable, Net
 
333

 
6,454

Fuel, Materials and Supplies
 
5,755

 
3,876

Accounts Payable
 
(28,643
)
 
8,783

Accrued Taxes, Net
 
32,131

 
37,739

Other Current Assets
 
(4,034
)
 
216

Other Current Liabilities
 
17,024

 
(3,780
)
Net Cash Flows from Operating Activities
 
151,543

 
214,978

 
 
 
 
 
INVESTING ACTIVITIES
 
 

 
 

Construction Expenditures
 
(256,741
)
 
(172,602
)
Change in Advances to Affiliates, Net
 

 
(8,884
)
Other Investing Activities
 
2,881

 
10,657

Net Cash Flows Used for Investing Activities
 
(253,860
)
 
(170,829
)
 
 
 
 
 
FINANCING ACTIVITIES
 
 

 
 

Issuance of Long-term Debt – Nonaffiliated
 
74,973

 

Change in Advances from Affiliates, Net
 
64,095

 

Retirement of Long-term Debt – Nonaffiliated
 
(34,010
)
 
(301
)
Principal Payments for Capital Lease Obligations
 
(2,785
)
 
(2,558
)
Dividends Paid on Common Stock
 

 
(41,250
)
Other Financing Activities
 
595

 
593

Net Cash Flows from (Used for) Financing Activities
 
102,868

 
(43,516
)
 
 
 
 
 
Net Increase in Cash and Cash Equivalents
 
551

 
633

Cash and Cash Equivalents at Beginning of Period
 
1,277

 
1,367

Cash and Cash Equivalents at End of Period
 
$
1,828

 
$
2,000

 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 

 
 

Cash Paid for Interest, Net of Capitalized Amounts
 
$
37,458

 
$
36,054

Net Cash Paid (Received) for Income Taxes
 
(416
)
 
2,026

Noncash Acquisitions Under Capital Leases
 
2,098

 
4,068

Construction Expenditures Included in Current Liabilities as of September 30,
 
33,527

 
33,820

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

155



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

The condensed notes to PSO’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to PSO.
 
Page
Number
 
 
Significant Accounting Matters
New Accounting Pronouncements
Comprehensive Income
Rate Matters
Commitments, Guarantees and Contingencies
Benefit Plans
Business Segments
Derivatives and Hedging
Fair Value Measurements
Income Taxes
Financing Activities
Variable Interest Entities

156





SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED


157



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

EXECUTIVE OVERVIEW

Regulatory Activity

2012 Texas Base Rate Case

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

2012 Louisiana Formula Rate Filing

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

2014 Louisiana Formula Rate Filing

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

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC.  Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC.  As of September 30, 2014, SWEPCo has incurred costs of $112 million and has contractual construction obligations of $84 million related to these projects.  SWEPCo will seek to recover these project costs from customers through filings at the state commissions and FERC. These environmental projects could be adversely impacted by pending carbon emission regulations.  See "CO2 Regulation"  section of “Environmental Issues” within “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries”.  As of September 30, 2014, the net book value of Welsh Plant, Units 1 and 3 was $335 million, before cost of removal, including materials and supplies inventory and CWIP.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 


158



Litigation and Environmental Issues

In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 170. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 249 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions of KWhs)
Retail:
 

 
 

 
 

 
 

Residential
1,949

 
2,081

 
4,974

 
5,021

Commercial
1,744

 
1,745

 
4,583

 
4,580

Industrial
1,511

 
1,443

 
4,453

 
4,167

Miscellaneous
20

 
19

 
60

 
60

Total Retail
5,224

 
5,288

 
14,070

 
13,828

 
 
 
 
 
 
 
 
Wholesale
2,458

 
2,479

 
7,022

 
7,053

 
 
 
 
 
 
 
 
Total KWhs
7,682

 
7,767

 
21,092

 
20,881


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

Summary of Heating and Cooling Degree Days
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
(in degree days)
Actual - Heating (a)

 

 
1,039

 
800

Normal - Heating (b)
1

 
1

 
748

 
754

 
 
 
 
 
 
 
 
Actual - Cooling (c)
1,232

 
1,418

 
1,917

 
2,137

Normal - Cooling (b)
1,404

 
1,397

 
2,162

 
2,155


(a)
Western Region heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Western Region cooling degree days are calculated on a 65 degree temperature base.

159




Third Quarter of 2014 Compared to Third Quarter of 2013
Reconciliation of Third Quarter of 2013 to Third Quarter of 2014
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
 
 
 
Third Quarter of 2013
 
$
7

 
 
 

Changes in Gross Margin:
 
 

Retail Margins (a)
 
(13
)
Off-system Sales
 
2

Transmission Revenues
 
(2
)
Other Revenues
 
1

Total Change in Gross Margin
 
(12
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(12
)
Asset Impairments and Other Related Charges
 
111

Depreciation and Amortization
 
(5
)
Taxes Other Than Income Taxes
 
(1
)
Interest Expense
 
1

Total Change in Expenses and Other
 
94

 
 
 

Income Tax Expense
 
(16
)
 
 
 

Third Quarter of 2014
 
$
73


(a)
Includes firm wholesale sales to municipals and cooperatives.

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

Retail Margins decreased $13 million primarily due to the following:
A $13 million decrease primarily due to a favorable Texas rate order adjustment in the third quarter of 2013 related to the Turk Plant.
A $13 million decrease in weather-related usage primarily due to a 13% decrease in cooling degree days.
These decreases were partially offset by:
An $11 million increase due to higher weather-normalized retail sales.
A $2 million increase in municipal and cooperative revenues due to formula rate adjustments.

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

Other Operation and Maintenance expenses increased $12 million primarily due to the following:
A $5 million increase in general and administrative expenses.
A $5 million increase in distribution expenses primarily due to overhead line maintenance expenses.
Asset Impairments and Other Related Charges decreased $111 million due to the third quarter 2013 write-off of AFUDC on the Turk Plant.
Depreciation and Amortization expenses increased $5 million primarily due to a greater depreciable base.
Income Tax Expense increased $16 million primarily due to an increase in pretax book income, partially offset by the recording of federal and state income tax return adjustments and other book/tax differences which are accounted for on a flow-through basis.

160



Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013
Reconciliation of Nine Months Ended September 30, 2013 to Nine Months Ended September 30, 2014
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
 
 
 
Nine Months Ended September 30, 2013
 
$
46

 
 
 

Changes in Gross Margin:
 
 

Retail Margins (a)
 
23

Off-system Sales
 
7

Transmission Revenues
 
(4
)
Other Revenues
 
2

Total Change in Gross Margin
 
28

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(33
)
Asset Impairments and Other Related Charges
 
111

Depreciation and Amortization
 
(6
)
Taxes Other Than Income Taxes
 
(4
)
Other Income
 
3

Interest Expense
 
5

Total Change in Expenses and Other
 
76

 
 
 

Income Tax Expense
 
(23
)
 
 
 

Nine Months Ended September 30, 2014
 
$
127


(a)
Includes firm wholesale sales to municipals and cooperatives.

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

Retail Margins increased $23 million primarily due to the following:
A $17 million net increase due to the Texas and Louisiana rate orders related to the Turk Plant.
A $15 million increase in municipal and cooperative revenues due to formula rate adjustments.
These increases were partially offset by:
A $9 million net decrease in weather-related usage primarily due to a 10% decrease in cooling degree days, partially offset by an increase in heating degree days.
Margins from Off-system Sales increased $7 million primarily due to increased market prices and higher physical sales margins.
Transmission Revenues decreased $4 million primarily due to lower SPP margins.
 
Expenses and Other and Income Tax Expense changed between years as follows:

Other Operation and Maintenance expenses increased $33 million primarily due to the following:
A $13 million increase in transmission expenses primarily due to increased SPP transmission services.
A $6 million increase in general and administrative expenses.
A $5 million increase in distribution expenses primarily due to overhead line maintenance expenses.
A $5 million increase in generation plant operation and maintenance expenses.
Asset Impairments and Other Related Charges decreased $111 million due to the third quarter 2013 write-off of AFUDC on the Turk Plant.
Depreciation and Amortization expenses increased $6 million primarily due to a greater depreciable base.
Taxes Other Than Income Taxes increased $4 million primarily due to higher property taxes.

161



Other Income increased $3 million primarily due to an increase in AFUDC as a result of environmental and transmission projects.
Interest Expense decreased $5 million primarily due to rate approvals in Louisiana and Texas and an increase in the debt component of AFUDC due to increased environmental and transmission projects.
Income Tax Expense increased $23 million primarily due to an increase in pretax book income, partially offset by the recording of federal and state income tax return adjustments in the third quarter of 2014 and other book/tax differences which are accounted for on a flow-through basis.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2013 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 249 for a discussion of accounting pronouncements.

162




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
REVENUES
 
 
 
 
 
 
 
 

Electric Generation, Transmission and Distribution
 
$
526,047

 
$
534,196

 
$
1,397,326

 
$
1,324,325

Sales to AEP Affiliates
 
5,203

 
18,296

 
22,748

 
41,935

Other Revenues
 
521

 
441

 
1,570

 
1,163

TOTAL REVENUES
 
531,771

 
552,933

 
1,421,644

 
1,367,423

 
 
 
 
 
 
 
 
 
EXPENSES
 
 

 
 

 
 

 
 

Fuel and Other Consumables Used for Electric Generation
 
194,175

 
202,024

 
500,878

 
490,447

Purchased Electricity for Resale
 
36,960

 
37,505

 
138,380

 
120,273

Purchased Electricity from AEP Affiliates
 

 
815

 
3,766

 
6,757

Other Operation
 
68,601

 
62,108

 
206,442

 
182,351

Maintenance
 
29,867

 
24,654

 
93,946

 
84,725

Asset Impairments and Other Related Charges
 

 
110,850

 

 
110,850

Depreciation and Amortization
 
46,791

 
41,846

 
138,316

 
132,460

Taxes Other Than Income Taxes
 
22,246

 
20,772

 
63,272

 
59,530

TOTAL EXPENSES
 
398,640

 
500,574

 
1,145,000

 
1,187,393

 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
133,131

 
52,359

 
276,644

 
180,030

 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 

 
 

 
 

 
 

Other Income
 
3,367

 
2,457

 
7,737

 
5,048

Interest Expense
 
(31,644
)
 
(32,614
)
 
(95,258
)
 
(100,151
)
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
 
104,854

 
22,202

 
189,123

 
84,927

 
 
 
 
 
 
 
 
 
Income Tax Expense
 
31,042

 
14,935

 
60,252

 
37,057

Equity Earnings of Unconsolidated Subsidiary
 
735

 
653

 
1,461

 
1,825

 
 
 
 
 
 
 
 
 
NET INCOME
 
74,547

 
7,920

 
130,332

 
49,695

 
 
 
 
 
 
 
 
 
Net Income Attributable to Noncontrolling Interest
 
1,109

 
1,058

 
3,337

 
3,204

 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER
 
$
73,438

 
$
6,862

 
$
126,995

 
$
46,491

The common stock of SWEPCo is wholly-owned by AEP.
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

163



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
Net Income
$
74,547

 
$
7,920

 
$
130,332

 
$
49,695

 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
 

 
 

 
 

 
 

Cash Flow Hedges, Net of Tax of $305 and $317 for the Three Months Ended September 30, 2014 and 2013, Respectively, and $881 and $902 for the Nine Months Ended September 30, 2014 and 2013, Respectively
567

 
589

 
1,636

 
1,675

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $126 and $35 for the Three Months Ended September 30, 2014 and 2013, Respectively, and $379 and $103 for the Nine Months Ended September 30, 2014 and 2013, Respectively
(235
)
 
(64
)
 
(704
)
 
(191
)
 
 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE INCOME
332

 
525

 
932

 
1,484

 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
74,879

 
8,445

 
131,264

 
51,179

 
 
 
 
 
 
 
 
Total Comprehensive Income Attributable to Noncontrolling Interest
1,109

 
1,058

 
3,337

 
3,204

 
 

 
 

 
 

 
 

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER
$
73,770

 
$
7,387

 
$
127,927

 
$
47,975

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

164



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
  SWEPCo Common Shareholder
 
 
 
 
 
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interest
 
Total
TOTAL EQUITY - DECEMBER 31, 2012
$
135,660

 
$
674,606

 
$
1,228,806

 
$
(17,860
)
 
$
261

 
$
2,021,473

 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
(93,750
)
 
 
 
 
 
(93,750
)
Common Stock Dividends – Nonaffiliated
 

 
 

 
 

 
 

 
(3,142
)
 
(3,142
)
Net Income
 

 
 

 
46,491

 
 

 
3,204

 
49,695

Other Comprehensive Income
 

 
 

 
 

 
1,484

 
 

 
1,484

TOTAL EQUITY - SEPTEMBER 30, 2013
$
135,660

 
$
674,606

 
$
1,181,547

 
$
(16,376
)
 
$
323

 
$
1,975,760

 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY - DECEMBER 31, 2013
$
135,660

 
$
674,606

 
$
1,253,617

 
$
(8,444
)
 
$
478

 
$
2,055,917

 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 

 
 

 
(75,000
)
 
 

 
 

 
(75,000
)
Common Stock Dividends – Nonaffiliated
 

 
 

 
 

 
 

 
(3,483
)
 
(3,483
)
Net Income
 

 
 

 
126,995

 
 

 
3,337

 
130,332

Other Comprehensive Income
 

 
 

 
 

 
932

 
 

 
932

TOTAL EQUITY - SEPTEMBER 30, 2014
$
135,660

 
$
674,606

 
$
1,305,612

 
$
(7,512
)
 
$
332

 
$
2,108,698

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

165



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2014 and December 31, 2013
(in thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2014
 
2013
CURRENT ASSETS
 
 
 
 
Cash and Cash Equivalents
(September 30, 2014 and December 31, 2013 Amounts Include $21,649 and $15,827, Respectively, Related to Sabine)
 
$
23,986

 
$
17,241

Accounts Receivable:
 
 
 
 
Customers
 
38,932

 
86,263

Affiliated Companies
 
28,296

 
22,389

Miscellaneous
 
30,855

 
27,175

Allowance for Uncollectible Accounts
 
(296
)
 
(1,418
)
Total Accounts Receivable
 
97,787

 
134,409

Fuel
(September 30, 2014 and December 31, 2013 Amounts Include $31,320 and $37,518, Respectively, Related to Sabine)
 
100,176

 
122,026

Materials and Supplies
 
74,212

 
74,862

Risk Management Assets
 
408

 
1,179

Deferred Income Tax Benefits
 
4,729

 
177,297

Accrued Tax Benefits
 
106,744

 
158

Regulatory Asset for Under-Recovered Fuel Costs
 
30,221

 
17,949

Prepayments and Other Current Assets
 
26,020

 
20,931

TOTAL CURRENT ASSETS
 
464,283

 
566,052

 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
Electric:
 
 
 
 
Generation
 
3,844,042

 
3,764,429

Transmission
 
1,265,646

 
1,165,167

Distribution
 
1,887,635

 
1,843,912

Other Property, Plant and Equipment (Including Plant to be Retired)
(September 30, 2014 and December 31, 2013 Amounts Include $286,792 and $291,556, Respectively, Related to Sabine)
 
876,552

 
869,230

Construction Work in Progress
 
395,740

 
281,849

Total Property, Plant and Equipment
 
8,269,615

 
7,924,587

Accumulated Depreciation and Amortization
(September 30, 2014 and December 31, 2013 Amounts Include $138,776 and $134,282, Respectively, Related to Sabine)
 
2,485,292

 
2,391,652

TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
5,784,323

 
5,532,935

 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
Regulatory Assets
 
364,968

 
369,905

Long-term Risk Management Assets
 
3

 

Deferred Charges and Other Noncurrent Assets
 
110,552

 
92,890

TOTAL OTHER NONCURRENT ASSETS
 
475,523

 
462,795

 
 
 
 
 
TOTAL ASSETS
 
$
6,724,129

 
$
6,561,782

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

166



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2014 and December 31, 2013
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2014
 
2013
 
 
(in thousands)
CURRENT LIABILITIES
 
 
 
 
Advances from Affiliates
 
$
6,329

 
$
9,180

Accounts Payable:
 
 
 
 
General
 
175,572

 
152,653

Affiliated Companies
 
44,666

 
56,923

Long-term Debt Due Within One Year – Nonaffiliated
 
306,750

 
3,250

Risk Management Liabilities
 
131

 

Customer Deposits
 
58,595

 
56,375

Accrued Taxes
 
70,222

 
41,508

Accrued Interest
 
19,589

 
43,996

Obligations Under Capital Leases
 
18,006

 
17,899

Regulatory Liability for Over-Recovered Fuel Costs
 

 
7,275

Other Current Liabilities
 
76,030

 
79,622

TOTAL CURRENT LIABILITIES
 
775,890

 
468,681

 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
Long-term Debt – Nonaffiliated
 
1,833,598

 
2,040,082

Deferred Income Taxes
 
1,285,125

 
1,271,478

Regulatory Liabilities and Deferred Investment Tax Credits
 
470,748

 
472,128

Asset Retirement Obligations
 
90,929

 
87,630

Employee Benefits and Pension Obligations
 
17,319

 
14,602

Obligations Under Capital Leases
 
95,036

 
105,086

Deferred Credits and Other Noncurrent Liabilities
 
46,786

 
46,178

TOTAL NONCURRENT LIABILITIES
 
3,839,541

 
4,037,184

 
 
 
 
 
TOTAL LIABILITIES
 
4,615,431

 
4,505,865

 
 
 
 
 
Rate Matters (Note 4)
 

 

Commitments and Contingencies (Note 5)
 

 

 
 
 
 
 
EQUITY
 
 
 
 
Common Stock – Par Value – $18 Per Share:
 
 
 
 
Authorized – 7,600,000 Shares
 
 
 
 
Outstanding – 7,536,640 Shares
 
135,660

 
135,660

Paid-in Capital
 
674,606

 
674,606

Retained Earnings
 
1,305,612

 
1,253,617

Accumulated Other Comprehensive Income (Loss)
 
(7,512
)
 
(8,444
)
TOTAL COMMON SHAREHOLDER’S EQUITY
 
2,108,366

 
2,055,439

 
 
 
 
 
Noncontrolling Interest
 
332

 
478

 
 
 
 
 
TOTAL EQUITY
 
2,108,698

 
2,055,917

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 
$
6,724,129

 
$
6,561,782

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

167



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2014 and 2013
(in thousands)
(Unaudited)
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
OPERATING ACTIVITIES
 
 

 
 

Net Income
 
$
130,332

 
$
49,695

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
 
Depreciation and Amortization
 
138,316

 
132,460

Deferred Income Taxes
 
181,482

 
27,736

Asset Impairments and Other Related Charges
 

 
110,850

Allowance for Equity Funds Used During Construction
 
(7,415
)
 
(4,872
)
Mark-to-Market of Risk Management Contracts
 
802

 
(591
)
Pension Contributions to Qualified Plan Trust
 
(3,832
)
 

Property Taxes
 
(12,503
)
 
(11,804
)
Fuel Over/Under-Recovery, Net
 
(19,547
)
 
(24,110
)
Change in Other Noncurrent Assets
 
11,926

 
21,935

Change in Other Noncurrent Liabilities
 
39

 
(10,203
)
Changes in Certain Components of Working Capital:
 
 
 
 
Accounts Receivable, Net
 
36,622

 
(7,384
)
Fuel, Materials and Supplies
 
22,500

 
8,638

Accounts Payable
 
(15,046
)
 
(7,626
)
Accrued Taxes, Net
 
(76,982
)
 
36,127

Accrued Interest
 
(24,406
)
 
(24,752
)
Other Current Assets
 
(7,448
)
 
(1,483
)
Other Current Liabilities
 
(2,983
)
 
(13,770
)
Net Cash Flows from Operating Activities
 
351,857

 
280,846

 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
Construction Expenditures
 
(351,666
)
 
(284,650
)
Change in Advances to Affiliates, Net
 

 
135,195

Other Investing Activities
 
4,334

 
(383
)
Net Cash Flows Used for Investing Activities
 
(347,332
)
 
(149,838
)
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
99,633

 

Credit Facility Borrowings
 

 
17,091

Change in Advances from Affiliates, Net
 
(2,851
)
 

Retirement of Long-term Debt – Nonaffiliated
 
(3,250
)
 
(3,250
)
Credit Facility Repayments
 

 
(19,694
)
Principal Payments for Capital Lease Obligations
 
(13,673
)
 
(13,394
)
Dividends Paid on Common Stock
 
(75,000
)
 
(93,750
)
Dividends Paid on Common Stock – Nonaffiliated
 
(3,483
)
 
(3,142
)
Other Financing Activities
 
844

 
746

Net Cash Flows from (Used for) Financing Activities
 
2,220

 
(115,393
)
 
 
 
 
 
Net Increase in Cash and Cash Equivalents
 
6,745

 
15,615

Cash and Cash Equivalents at Beginning of Period
 
17,241

 
2,036

Cash and Cash Equivalents at End of Period
 
$
23,986

 
$
17,651

 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
113,137

 
$
115,627

Net Cash Paid (Received) for Income Taxes
 
(13,820
)
 
265

Noncash Acquisitions Under Capital Leases
 
3,923

 
3,848

Construction Expenditures Included in Current Liabilities as of September 30,
 
88,291

 
44,815

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 170.

168



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

The condensed notes to SWEPCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to SWEPCo.
 
Page
Number
 
 
Significant Accounting Matters
New Accounting Pronouncements
Comprehensive Income
Rate Matters
Commitments, Guarantees and Contingencies
Disposition and Impairments
Benefit Plans
Business Segments
Derivatives and Hedging
Fair Value Measurements
Income Taxes
Financing Activities
Variable Interest Entities





169



INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to condensed financial statements that follow are a combined presentation for the Registrant Subsidiaries.  The following list indicates the registrants to which the footnotes apply:
 
 
Page
Number
 
 
 
Significant Accounting Matters
APCo, I&M, OPCo, PSO, SWEPCo
New Accounting Pronouncements
APCo, I&M, OPCo, PSO, SWEPCo
Comprehensive Income
APCo, I&M, OPCo, PSO, SWEPCo
Rate Matters
APCo, I&M, OPCo, PSO, SWEPCo
Commitments, Guarantees and Contingencies
APCo, I&M, OPCo, PSO, SWEPCo
Disposition and Impairments
OPCo, SWEPCo
Benefit Plans
APCo, I&M, OPCo, PSO, SWEPCo
Business Segments
APCo, I&M, OPCo, PSO, SWEPCo
Derivatives and Hedging
APCo, I&M, OPCo, PSO, SWEPCo
Fair Value Measurements
APCo, I&M, OPCo, PSO, SWEPCo
Income Taxes
APCo, I&M, OPCo, PSO, SWEPCo
Financing Activities
APCo, I&M, OPCo, PSO, SWEPCo
Variable Interest Entities
APCo, I&M, OPCo, PSO, SWEPCo


170



1.  SIGNIFICANT ACCOUNTING MATTERS

General

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

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary.  Net income for the three and nine months ended September 30, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 25, 2014.

Revenue Recognition

Electricity Supply and Delivery Activities - Transactions with PJM

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

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

SPP Integrated Power Market

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


171



2. NEW ACCOUNTING PRONOUNCEMENTS

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

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

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

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014 with early adoption permitted. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share.

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

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

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



172



3.  COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2014 and 2013.  All amounts in the following tables are presented net of related income taxes.
 
APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2014
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2014
 
$

 
$
3,596

 
$
(899
)
 
$
2,697

Change in Fair Value Recognized in AOCI
 

 

 

 

Amounts Reclassified from AOCI
 

 
170

 
(333
)
 
(163
)
Net Current Period Other
Comprehensive Income
 

 
170

 
(333
)
 
(163
)
Balance in AOCI as of September 30, 2014
 
$

 
$
3,766

 
$
(1,232
)
 
$
2,534


APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2013
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2013
 
$
197

 
$
2,583

 
$
(30,615
)
 
$
(27,835
)
Change in Fair Value Recognized in AOCI
 
(47
)
 

 

 
(47
)
Amounts Reclassified from AOCI
 
(184
)
 
253

 
359

 
428

Net Current Period Other
Comprehensive Income
 
(231
)
 
253

 
359

 
381

Balance in AOCI as of September 30, 2013
 
$
(34
)
 
$
2,836

 
$
(30,256
)
 
$
(27,454
)


173



APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2014
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2013
 
$
94

 
$
3,090

 
$
(233
)
 
$
2,951

Change in Fair Value Recognized in AOCI
 
1,686

 

 

 
1,686

Amounts Reclassified from AOCI
 
(1,780
)
 
676

 
(999
)
 
(2,103
)
Net Current Period Other
Comprehensive Income
 
(94
)
 
676

 
(999
)
 
(417
)
Balance in AOCI as of September 30, 2014
 
$

 
$
3,766

 
$
(1,232
)
 
$
2,534


APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2013
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2012
 
$
(644
)
 
$
2,077

 
$
(31,331
)
 
$
(29,898
)
Change in Fair Value Recognized in AOCI
 
684

 

 

 
684

Amounts Reclassified from AOCI
 
(74
)
 
759

 
1,075

 
1,760

Net Current Period Other
Comprehensive Income
 
610

 
759

 
1,075

 
2,444

Balance in AOCI as of September 30, 2013
 
$
(34
)
 
$
2,836

 
$
(30,256
)
 
$
(27,454
)


174



I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2014
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2014
 
$

 
$
(15,155
)
 
$
507

 
$
(14,648
)
Change in Fair Value Recognized in AOCI
 

 

 

 

Amounts Reclassified from AOCI
 

 
410

 
42

 
452

Net Current Period Other
Comprehensive Income
 

 
410

 
42

 
452

Balance in AOCI as of September 30, 2014
 
$

 
$
(14,745
)
 
$
549

 
$
(14,196
)

I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2013
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2013
 
$
147

 
$
(16,796
)
 
$
(8,439
)
 
$
(25,088
)
Change in Fair Value Recognized in AOCI
 
(49
)
 

 

 
(49
)
Amounts Reclassified from AOCI
 
(117
)
 
410

 
174

 
467

Net Current Period Other
Comprehensive Income
 
(166
)
 
410

 
174

 
418

Balance in AOCI as of September 30, 2013
 
$
(19
)
 
$
(16,386
)
 
$
(8,265
)
 
$
(24,670
)


175



I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2014
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2013
 
$
46

 
$
(15,976
)
 
$
421

 
$
(15,509
)
Change in Fair Value Recognized in AOCI
 
1,130

 

 

 
1,130

Amounts Reclassified from AOCI
 
(1,176
)
 
1,231

 
128

 
183

Net Current Period Other
Comprehensive Income
 
(46
)
 
1,231

 
128

 
1,313

Balance in AOCI as of September 30, 2014
 
$

 
$
(14,745
)
 
$
549

 
$
(14,196
)

I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2013
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2012
 
$
(446
)
 
$
(19,647
)
 
$
(8,790
)
 
$
(28,883
)
Change in Fair Value Recognized in AOCI
 
443

 
2,248

 

 
2,691

Amounts Reclassified from AOCI
 
(16
)
 
1,013

 
525

 
1,522

Net Current Period Other
Comprehensive Income
 
427

 
3,261

 
525

 
4,213

Balance in AOCI as of September 30, 2013
 
$
(19
)
 
$
(16,386
)
 
$
(8,265
)
 
$
(24,670
)


176



OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2014
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2014
 
$

 
$
6,288

 
$

 
$
6,288

Change in Fair Value Recognized in AOCI
 

 

 

 

Amounts Reclassified from AOCI
 

 
(343
)
 

 
(343
)
Net Current Period Other
Comprehensive Income
 

 
(343
)
 

 
(343
)
Balance in AOCI as of September 30, 2014
 
$

 
$
5,945

 
$

 
$
5,945

 
OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2013
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2013
 
$
289

 
$
7,415

 
$
(166,369
)
 
$
(158,665
)
Change in Fair Value Recognized in AOCI
 
(86
)
 

 

 
(86
)
Amounts Reclassified from AOCI
 
(250
)
 
(339
)
 
2,985

 
2,396

Net Current Period Other
Comprehensive Income
 
(336
)
 
(339
)
 
2,985

 
2,310

Distribution of Cook Coal Terminal to Parent
 

 

 
19,652

 
19,652

Balance in AOCI as of September 30, 2013
 
$
(47
)
 
$
7,076

 
$
(143,732
)
 
$
(136,703
)


177



OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2014
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2013
 
$
105

 
$
6,974

 
$

 
$
7,079

Change in Fair Value Recognized in AOCI
 

 

 

 

Amounts Reclassified from AOCI
 
(105
)
 
(1,029
)
 

 
(1,134
)
Net Current Period Other
Comprehensive Income
 
(105
)
 
(1,029
)
 

 
(1,134
)
Balance in AOCI as of September 30, 2014
 
$

 
$
5,945

 
$

 
$
5,945


OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2013
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2012
 
$
(912
)
 
$
8,095

 
$
(172,908
)
 
$
(165,725
)
Change in Fair Value Recognized in AOCI
 
907

 

 

 
907

Amounts Reclassified from AOCI
 
(42
)
 
(1,019
)
 
9,524

 
8,463

Net Current Period Other
Comprehensive Income
 
865

 
(1,019
)
 
9,524

 
9,370

Distribution of Cook Coal Terminal to Parent
 

 

 
19,652

 
19,652

Balance in AOCI as of September 30, 2013
 
$
(47
)
 
$
7,076

 
$
(143,732
)
 
$
(136,703
)


178



PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2014
 
 
Cash Flow Hedges
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2014
 
$

 
$
5,322

 
$
5,322

Change in Fair Value Recognized in AOCI
 

 

 

Amounts Reclassified from AOCI
 

 
(190
)
 
(190
)
Net Current Period Other Comprehensive Income
 

 
(190
)
 
(190
)
Balance in AOCI as of September 30, 2014
 
$

 
$
5,132

 
$
5,132

 
PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2013
 
 
Cash Flow Hedges
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2013
 
$
(21
)
 
$
6,081

 
$
6,060

Change in Fair Value Recognized in AOCI
 
32

 

 
32

Amounts Reclassified from AOCI
 
(14
)
 
(190
)
 
(204
)
Net Current Period Other Comprehensive Income
 
18

 
(190
)
 
(172
)
Balance in AOCI as of September 30, 2013
 
$
(3
)
 
$
5,891

 
$
5,888



179



PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2014
 
 
Cash Flow Hedges
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2013
 
$
57

 
$
5,701

 
$
5,758

Change in Fair Value Recognized in AOCI
 

 

 

Amounts Reclassified from AOCI
 
(57
)
 
(569
)
 
(626
)
Net Current Period Other Comprehensive Income
 
(57
)
 
(569
)
 
(626
)
Balance in AOCI as of September 30, 2014
 
$

 
$
5,132

 
$
5,132


PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2013
 
 
Cash Flow Hedges
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2012
 
$
21

 
$
6,460

 
$
6,481

Change in Fair Value Recognized in AOCI
 
7

 
1

 
8

Amounts Reclassified from AOCI
 
(31
)
 
(570
)
 
(601
)
Net Current Period Other Comprehensive Income
 
(24
)
 
(569
)
 
(593
)
Balance in AOCI as of September 30, 2013
 
$
(3
)
 
$
5,891

 
$
5,888



180



SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2014
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2014
 
$

 
$
(12,169
)
 
$
4,325

 
$
(7,844
)
Change in Fair Value Recognized in AOCI
 

 

 

 

Amounts Reclassified from AOCI
 

 
567

 
(235
)
 
332

Net Current Period Other
Comprehensive Income
 

 
567

 
(235
)
 
332

Balance in AOCI as of September 30, 2014
 
$

 
$
(11,602
)
 
$
4,090

 
$
(7,512
)

SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2013
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2013
 
$
(26
)
 
$
(14,437
)
 
$
(2,438
)
 
$
(16,901
)
Change in Fair Value Recognized in AOCI
 
40

 

 

 
40

Amounts Reclassified from AOCI
 
(17
)
 
566

 
(64
)
 
485

Net Current Period Other
Comprehensive Income
 
23

 
566

 
(64
)
 
525

Balance in AOCI as of September 30, 2013
 
$
(3
)
 
$
(13,871
)
 
$
(2,502
)
 
$
(16,376
)


181



SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2014
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2013
 
$
66

 
$
(13,304
)
 
$
4,794

 
$
(8,444
)
Change in Fair Value Recognized in AOCI
 

 

 

 

Amounts Reclassified from AOCI
 
(66
)
 
1,702

 
(704
)
 
932

Net Current Period Other
Comprehensive Income
 
(66
)
 
1,702

 
(704
)
 
932

Balance in AOCI as of September 30, 2014
 
$

 
$
(11,602
)
 
$
4,090

 
$
(7,512
)

SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2013
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2012
 
$
22

 
$
(15,571
)
 
$
(2,311
)
 
$
(17,860
)
Change in Fair Value Recognized in AOCI
 
13

 

 

 
13

Amounts Reclassified from AOCI
 
(38
)
 
1,700

 
(191
)
 
1,471

Net Current Period Other
Comprehensive Income
 
(25
)
 
1,700

 
(191
)
 
1,484

Balance in AOCI as of September 30, 2013
 
$
(3
)
 
$
(13,871
)
 
$
(2,502
)
 
$
(16,376
)


182



Reclassifications from Accumulated Other Comprehensive Income

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

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2014 and 2013
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Three Months Ended September 30,
 
 
2014
 
2013
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Electric Generation, Transmission and Distribution Revenues
 
$

 
$
(75
)
Purchased Electricity for Resale
 

 
21

Other Operation Expense
 

 
(14
)
Maintenance Expense
 

 
(11
)
Property, Plant and Equipment
 

 
(15
)
Regulatory Assets/(Liabilities), Net (a)
 

 
(190
)
Subtotal  Commodity
 

 
(284
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
262

 
390

Subtotal  Interest Rate and Foreign Currency
 
262

 
390

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
262

 
106

Income Tax (Expense) Credit
 
92

 
37

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
170

 
69

 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 
(1,281
)
 
(1,282
)
Amortization of Actuarial (Gains)/Losses
 
769

 
1,834

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(512
)
 
552

Income Tax (Expense) Credit
 
(179
)
 
193

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(333
)
 
359

 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(163
)
 
$
428



183



APCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2014 and 2013
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Electric Generation, Transmission and Distribution Revenues
 
$

 
$
(53
)
Purchased Electricity for Resale
 
(526
)
 
47

Other Operation Expense
 
(10
)
 
(38
)
Maintenance Expense
 
(20
)
 
(29
)
Property, Plant and Equipment
 
(17
)
 
(34
)
Regulatory Assets/(Liabilities), Net (a)
 
(2,165
)
 
(9
)
Subtotal  Commodity
 
(2,738
)
 
(116
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
1,042

 
1,169

Subtotal  Interest Rate and Foreign Currency
 
1,042

 
1,169

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(1,696
)
 
1,053

Income Tax (Expense) Credit
 
(592
)
 
368

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(1,104
)
 
685

 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 
(3,846
)
 
(3,847
)
Amortization of Actuarial (Gains)/Losses
 
2,309

 
5,501

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(1,537
)
 
1,654

Income Tax (Expense) Credit
 
(538
)
 
579

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(999
)
 
1,075

 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(2,103
)
 
$
1,760



184



I&M

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2014 and 2013
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Three Months Ended September 30,
 
 
2014
 
2013
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Electric Generation, Transmission and Distribution Revenues
 
$

 
$
(173
)
Purchased Electricity for Resale
 

 
47

Other Operation Expense
 

 
(8
)
Maintenance Expense
 

 
(5
)
Property, Plant and Equipment
 

 
(10
)
Regulatory Assets/(Liabilities), Net (a)
 

 
(31
)
Subtotal  Commodity
 

 
(180
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
631

 
631

Subtotal  Interest Rate and Foreign Currency
 
631

 
631

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
631

 
451

Income Tax (Expense) Credit
 
221

 
158

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
410

 
293

 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 
(200
)
 
(199
)
Amortization of Actuarial (Gains)/Losses
 
264

 
467

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
64

 
268

Income Tax (Expense) Credit
 
22

 
94

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
42

 
174

 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
452

 
$
467



185



I&M

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2014 and 2013
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Electric Generation, Transmission and Distribution Revenues
 
$

 
$
(89
)
Purchased Electricity for Resale
 
(812
)
 
115

Other Operation Expense
 
(7
)
 
(23
)
Maintenance Expense
 
(7
)
 
(14
)
Property, Plant and Equipment
 
(10
)
 
(20
)
Regulatory Assets/(Liabilities), Net (a)
 
(973
)
 
7

Subtotal  Commodity
 
(1,809
)
 
(24
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
1,893

 
1,558

Subtotal  Interest Rate and Foreign Currency
 
1,893

 
1,558

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
84

 
1,534

Income Tax (Expense) Credit
 
29

 
537

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
55

 
997

 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 
(597
)
 
(596
)
Amortization of Actuarial (Gains)/Losses
 
791

 
1,404

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
194

 
808

Income Tax (Expense) Credit
 
66

 
283

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
128

 
525

 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
183

 
$
1,522



186



OPCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2014 and 2013
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Three Months Ended September 30,
 
 
2014
 
2013
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Electric Generation, Transmission and Distribution Revenues
 
$

 
$
(461
)
Purchased Electricity for Resale
 

 
129

Other Operation Expense
 

 
(20
)
Maintenance Expense
 

 
(11
)
Property, Plant and Equipment
 

 
(21
)
Subtotal  Commodity
 

 
(384
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Depreciation and Amortization Expense
 
(3
)
 
2

Interest Expense
 
(524
)
 
(524
)
Subtotal  Interest Rate and Foreign Currency
 
(527
)
 
(522
)
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(527
)
 
(906
)
Income Tax (Expense) Credit
 
(184
)
 
(317
)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(343
)
 
(589
)
 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 

 
(1,451
)
Amortization of Actuarial (Gains)/Losses
 

 
6,044

Reclassifications from AOCI, before Income Tax (Expense) Credit
 

 
4,593

Income Tax (Expense) Credit
 

 
1,608

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 

 
2,985

 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(343
)
 
$
2,396



187



OPCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2014 and 2013
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Electric Generation, Transmission and Distribution Revenues
 
$

 
$
(246
)
Purchased Electricity for Resale
 

 
309

Other Operation Expense
 
(11
)
 
(57
)
Maintenance Expense
 
(11
)
 
(26
)
Property, Plant and Equipment
 
(18
)
 
(44
)
Regulatory Assets/(Liabilities), Net (a)
 
(122
)
 

Subtotal  Commodity
 
(162
)
 
(64
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Depreciation and Amortization Expense
 
(9
)
 
5

Interest Expense
 
(1,572
)
 
(1,573
)
Subtotal  Interest Rate and Foreign Currency
 
(1,581
)
 
(1,568
)
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(1,743
)
 
(1,632
)
Income Tax (Expense) Credit
 
(609
)
 
(571
)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(1,134
)
 
(1,061
)
 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 

 
(4,388
)
Amortization of Actuarial (Gains)/Losses
 

 
19,040

Reclassifications from AOCI, before Income Tax (Expense) Credit
 

 
14,652

Income Tax (Expense) Credit
 

 
5,128

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 

 
9,524

 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(1,134
)
 
$
8,463



188



PSO

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2014 and 2013
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Three Months Ended September 30,
 
 
2014
 
2013
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Other Operation Expense
 
$

 
$
(10
)
Maintenance Expense
 

 
(5
)
Property, Plant and Equipment
 

 
(7
)
Subtotal  Commodity
 

 
(22
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
(292
)
 
(292
)
Subtotal  Interest Rate and Foreign Currency
 
(292
)
 
(292
)
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(292
)
 
(314
)
Income Tax (Expense) Credit
 
(102
)
 
(110
)
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(190
)
 
$
(204
)
 
PSO

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2014 and 2013
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Other Operation Expense
 
$
(8
)
 
$
(25
)
Maintenance Expense
 
(9
)
 
(9
)
Property, Plant and Equipment
 
(13
)
 
(14
)
Regulatory Assets/(Liabilities), Net (a)
 
(58
)
 

Subtotal  Commodity
 
(88
)
 
(48
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
(876
)
 
(876
)
Subtotal  Interest Rate and Foreign Currency
 
(876
)
 
(876
)
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(964
)
 
(924
)
Income Tax (Expense) Credit
 
(338
)
 
(323
)
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(626
)
 
$
(601
)


189



SWEPCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2014 and 2013
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Three Months Ended September 30,
 
 
2014
 
2013
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Other Operation Expense
 
$

 
$
(12
)
Maintenance Expense
 

 
(7
)
Property, Plant and Equipment
 

 
(8
)
Subtotal  Commodity
 

 
(27
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
872

 
872

Subtotal  Interest Rate and Foreign Currency
 
872

 
872

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
872

 
845

Income Tax (Expense) Credit
 
305

 
296

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
567

 
549

 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 
(478
)
 
(446
)
Amortization of Actuarial (Gains)/Losses
 
118

 
348

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(360
)
 
(98
)
Income Tax (Expense) Credit
 
(125
)
 
(34
)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(235
)
 
(64
)
 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
332

 
$
485

 

190



SWEPCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2014 and 2013
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Other Operation Expense
 
$
(13
)
 
$
(28
)
Maintenance Expense
 
(10
)
 
(14
)
Property, Plant and Equipment
 
(11
)
 
(16
)
Regulatory Assets/(Liabilities), Net (a)
 
(67
)
 

Subtotal  Commodity
 
(101
)
 
(58
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
2,616

 
2,616

Subtotal  Interest Rate and Foreign Currency
 
2,616

 
2,616

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
2,515

 
2,558

Income Tax (Expense) Credit
 
879

 
896

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
1,636

 
1,662

 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 
(1,433
)
 
(1,338
)
Amortization of Actuarial (Gains)/Losses
 
351

 
1,044

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(1,082
)
 
(294
)
Income Tax (Expense) Credit
 
(378
)
 
(103
)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(704
)
 
(191
)
 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
932

 
$
1,471

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


191



4.  RATE MATTERS

As discussed in the 2013 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2013 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2014 and updates the 2013 Annual Report.

Regulatory Assets Pending Final Regulatory Approval
 
 
APCo
 
 
September 30,
 
December 31,
 
 
2014
 
2013
Noncurrent Regulatory Assets
 
(in thousands)
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
West Virginia Vegetation Management Program
 
$
16,115

 
$

Regulatory Assets Currently Not Earning a Return
 
 
 
 
Storm Related Costs
 
65,206

 
65,206

IGCC Pre-Construction Costs
 
20,528

 

Mountaineer Carbon Capture and Storage Product Validation Facility
 
13,264

 
13,264

Expanded Net Energy Charge  Coal Inventory
 
8,554

 
20,528

Virginia Demand Response Program Costs
 
7,779

 
5,012

Virginia Environmental Rate Adjustment Clause
 
1,941

 
2,440

Mountaineer Carbon Capture and Storage Commercial Scale Facility
 
1,287

 
1,287

Transmission Agreement Phase-In
 

 
3,313

Other Regulatory Assets Pending Final Regulatory Approval
 
1,201

 
168

Total Regulatory Assets Pending Final Regulatory Approval
 
$
135,875

 
$
111,218

 
 
I&M
 
 
September 30,
 
December 31,
 
 
2014
 
2013
Noncurrent Regulatory Assets
 
(in thousands)
 
 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
Cook Plant Turbine
 
$
5,810

 
$
3,452

Stranded Costs on Abandoned Plants
 
3,897

 
3,896

Storm Related Costs
 
1,855

 
1,836

Michigan Deferred Cook Plant Life Cycle Management Project Costs
 
1,093

 
164

Indiana Deferred Cook Plant Life Cycle Management Project Costs
 

 
4,093

Indiana Under-Recovered Capacity Costs
 

 
21,945

Other Regulatory Assets Pending Final Regulatory Approval
 
1,065

 

Total Regulatory Assets Pending Final Regulatory Approval
 
$
13,720

 
$
35,386

 
 
OPCo
 
 
September 30,
 
December 31,
 
 
2014
 
2013
Noncurrent Regulatory Assets
 
(in thousands)
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
Ohio Economic Development Rider
 
$

 
$
13,854

Regulatory Assets Currently Not Earning a Return
 
 

 
 

Ormet Special Rate Recovery Mechanism
 
10,483

 
35,631

Storm Related Costs
 

 
57,589

Total Regulatory Assets Pending Final Regulatory Approval
 
$
10,483

 
$
107,074


192



 
 
PSO
 
 
September 30,
 
December 31,
 
 
2014
 
2013
Noncurrent Regulatory Assets
 
(in thousands)
 
 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 

 
 

Storm Related Costs
 
$
17,936

 
$
18,743

Other Regulatory Assets Pending Final Regulatory Approval
 
1,079

 
845

Total Regulatory Assets Pending Final Regulatory Approval
 
$
19,015

 
$
19,588

 
 
SWEPCo
 
 
September 30,
 
December 31,
 
 
2014
 
2013
Noncurrent Regulatory Assets
 
(in thousands)
 
 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
Rate Case Expenses
 
$
8,051

 
$
7,934

Mountaineer Carbon Capture and Storage Commercial Scale Facility
 
1,143

 
1,143

Other Regulatory Assets Pending Final Regulatory Approval
 
2,175

 
1,951

Total Regulatory Assets Pending Final Regulatory Approval
 
$
11,369

 
$
11,028


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

OPCo Rate Matters

Ohio Electric Security Plan Filings

2009 – 2011 ESP

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

In October 2011, the PUCO issued an order in the remand proceeding. As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011. In February 2012, the Ohio Consumers’ Counsel (OCC) and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 - 2011 and various aspects of the approved environmental carrying charge. In February 2014, the Supreme Court of Ohio affirmed the PUCO’s decision and rejected all appeals filed by the OCC and the IEU.

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

193



accumulated deferred income tax credit which, as of September 30, 2014, could reduce carrying costs by $28 million including $14 million of unrecognized equity carrying costs. As of September 30, 2014, OPCo’s net deferred fuel balance was $395 million, excluding unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending.

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

June 2012 – May 2015 ESP Including Capacity Charge

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

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and is $150/MW day from June 2014 through May 2015.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.  

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR was collected from customers at $3.50/MWh through May 2014 and is currently collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. As of September 30, 2014, OPCo's incurred deferred capacity costs balance of $409 million, including debt carrying costs, was recorded in regulatory assets on the condensed balance sheet.

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

In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications which included the delay of the energy auctions that were originally ordered in the ESP order. As ordered, in February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. Also as ordered, in May 2014 and September 2014, OPCo conducted energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for the remaining 40% of the SSO load for delivery from January 2015 through May 2015. OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In May 2014, an independent auditor was selected by the PUCO and an audit of the recovery of the fixed fuel costs began in June 2014. In October 2014, the independent auditor filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88 capacity charge, the independent auditor recommends a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and intends to oppose the findings in the audit report.


194



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

Proposed June 2015 - May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM capacity and energy auction-based generation through OPCo. The proposal also includes a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based purchase power agreement. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In May 2014, intervenors and the PUCO staff filed testimony that provided various recommendations including the rejection and/or modification of various riders, including the DIR and the proposed PPA. Hearings at the PUCO in the ESP case were held in June 2014. Additionally, in July 2014, OPCo submitted a separate application to continue the RSR established in the June 2012 - May 2015 ESP to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. In October 2014, OPCo filed a separate application with the PUCO to propose a new PPA for inclusion in the PPA rider, discussed above. The new PPA would include an additional 2,671 MW to be purchased from AGR over the life of the respective generating units.

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

Significantly Excessive Earnings Test Filings

In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending.

In March 2014, the PUCO approved a stipulation agreement between OPCo and the PUCO staff that there were no significantly excessive earnings in 2011 for CSPCo or OPCo. In May 2014, the PUCO approved a stipulation agreement between OPCo and the PUCO staff that there were no significantly excessive earnings in 2012 for OPCo. In May 2014, OPCo filed its 2013 SEET filing with the PUCO. In October 2014, OPCo entered into a stipulation agreement with the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2013 for OPCo. A hearing at the PUCO related to the 2013 SEET filing is scheduled for November 2014.

Management believes its financial statements adequately address the impact of SEET requirements.

Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo’s generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition.


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Storm Damage Recovery Rider (SDRR)

In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates to recover 2012 incremental storm distribution expenses. In April 2014, the PUCO approved a stipulation agreement between OPCo, the PUCO staff and all intervenors, except the Ohio Consumers’ Counsel, to recover $55 million over a 12-month period. The agreement also provided that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period. Compliance tariffs were filed with the PUCO and new rates were implemented in April 2014. In May 2014, the PUCO upheld the settlement agreement on rehearing.

2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.

In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges. In September 2014, the Supreme Court of Ohio upheld the PUCO order. A review of the coal reserve valuation by an outside consultant is still pending. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC). The PUCO subsequently ruled in the PIRR proceeding that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes. See the 2009 - 2011 ESP section of “Ohio Electric Security Plan Filings” above for a discussion of the PUCO order in the PIRR proceeding. In May 2014, the PUCO issued an order that generally approved OPCo's 2010-2011 fuel costs and rejected the auditor recommendation to adjust the WACC carrying charges related to accumulated deferred income taxes. Additionally, the PUCO requested further review related to an affiliate barging agreement and the modification of certain fuel procurement processes and practices. Further, the order provided for the auditor to address any remaining concerns in their next audit report, as they deem necessary. In July 2014, the PUCO issued an order that denied all requests for rehearing.

2012 and 2013 Fuel Adjustment Clause Audits

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


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Ormet

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

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

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

Ohio IGCC Plant

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

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

SWEPCo Rate Matters

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


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

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

Texas Transmission Cost Recovery Factor Filing

In May 2014, SWEPCo filed an application with the PUCT to implement its transmission cost recovery factor (TCRF) requesting additional annual revenue of $15 million. The TCRF is designed to recover increases from the amounts included in SWEPCo’s Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC. SWEPCo’s application included Turk Plant transmission-related costs. In July 2014, intervenors filed testimony with recommendations that included revenue increases ranging from $1 million to $10 million. Hearings at the PUCT were held in August 2014. In October 2014, the Administrative Law Judge issued a proposal for decision that recommended approval of SWEPCo's application with an increase in annual revenue of $14 million. An order is anticipated in the fourth quarter of 2014. If the PUCT were to disallow any portion of the TCRF, it could reduce future net income and cash flows and impact financial condition.

2012 Louisiana Formula Rate Filing

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

2014 Louisiana Formula Rate Filing

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

Welsh Plant, Units 1 and 3 - Environmental Projects

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

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2014, SWEPCo has incurred costs of $112 million and has contractual construction obligations of $84 million related to these projects.  SWEPCo will seek to recover these project costs from customers through filings at the state commissions and FERC. These environmental projects could be adversely impacted by pending carbon emission regulations.  As of September 30, 2014, the net book value of Welsh Plant, Units 1 and 3 was $335 million, before cost of removal, including materials and supplies inventory and CWIP.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 

APCo Rate Matters

Plant Transfer

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a cost-of-service basis. West Virginia generally allows for timely recovery of fuel costs through an expanded net energy cost which trues-up to actual expenses. In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo until APCo's West Virginia base rates are updated. See the "2014 West Virginia Base Rate Case" below. In April 2014, AGR and WPCo filed a request with the FERC for approval to transfer AGR’s one-half interest in the Mitchell Plant to WPCo. In June 2014, the FERC issued an order approving this request.
 
In August 2014, intervenors filed testimony with the WVPSC with recommendations that ranged from transferring only a portion of the one-half interest in the Mitchell Plant to denial of the transfer in its entirety. Additionally, recommendations included reducing the net book value of the one-half interest in the Mitchell Plant and reducing the base rate surcharge to $87 million. Intervenors also expressed concerns related to the amount of liability assumed by WPCo should the transfer be approved. In October 2014, a stipulation agreement between APCo, WPCo, the WVPSC staff and intervenors in the case was filed with the WVPSC. The stipulation agreement recommended approval for WPCo to acquire, at net book value, the one-half interest in the Mitchell Plant, excluding $20 million of certain assets, which will be paid by WPCo and recovered as a regulatory asset over the life of the plant. Additionally, the agreement stated that 82.5% of the costs associated with the acquired interest will be reflected in rates effective from the date of the transfer via a surcharge with an offset in ENEC revenues. The remaining 17.5% of the costs associated with the acquired interest is to be included in rates by January 2020. The agreement also proposed that WPCo share the energy margins for 82.5% of the plant’s output with ratepayers and that WPCo retain all of the energy margins from sales into the wholesale market on the remaining 17.5%, to offset fixed costs associated with this portion, until the remaining portion is approved for inclusion in rates. Management anticipates an order related to the proposed transfer will be issued in the fourth quarter of 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

APCo IGCC Plant

As of September 30, 2014, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $10 million applicable to its Virginia jurisdiction.  In March 2014, APCo submitted a request to the Virginia SCC as part of the 2014 Virginia Biennial Base Rate Case to amortize the Virginia jurisdictional share of these costs over two years. In June 2014, APCo submitted a request to the WVPSC as part of the 2014 West Virginia Base Rate Case to amortize the West Virginia jurisdictional share of these costs over five years. In August 2014, intervenors filed testimony with the Virginia SCC that recommended APCo write-off the entire $10 million applicable to the Virginia jurisdiction. Hearings at the Virginia SCC were held in September 2014. A decision is expected in November 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


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2013 Virginia Transmission Rate Adjustment Clause (transmission RAC)

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

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a biennial generation and distribution base rate case with the Virginia SCC. In accordance with a Virginia statute, APCo did not request a change in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to changes in the expected service lives of various generating units and the extended recovery through 2040 of the net book value of certain planned 2015 plant retirements. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to IGCC and other deferred costs.

In August 2014, the Virginia SCC staff and intervenors filed testimony concluding that APCo's adjusted earned rate of return on common equity for 2012 and 2013, reflecting their recommended adjustments, was above the allowed threshold. Recommendations included (a) refunds to customers ranging from $15 million to $22 million, (b) the write-off of certain APCo assets, including IGCC pre-construction costs and previously approved 2009 storm costs, totaling $27 million and (c) $38 million in increased depreciation expense annually, retroactive to January 1, 2014, primarily related to accelerating depreciation on APCo generation assets to be retired in the second quarter of 2015. Hearings at the Virginia SCC were held in September 2014. A decision is expected in November 2014. If any of these costs are not recoverable, or if refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

2014 West Virginia Base Rate Case

In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $156 million, based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units. The filing also requested recovery of $77 million over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $38 million annually to recover vegetation management costs, including a return on capital investment. In October 2014, the WVPSC approved APCo's motion to revise the procedural schedule which included the extension of the intervention period to November 2014 and a delay in the implementation of new rates from April 2015 to May 2015. Hearings at the WVPSC are scheduled for January 2015. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting authority to merge WPCo into APCo. In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC. In April 2013, the FERC approved the merger. Also in December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant. In June 2013, the WVPSC issued an order consolidating the merger case with APCo’s plant asset transfer case. In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo. In December 2013, the WVPSC issued an order that deferred ruling on the

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merger of WPCo into APCo. The order also directed APCo and WPCo to submit a plan with the WVPSC identifying a course of action to serve the load of WPCo. See the “Plant Transfer” section of APCo Rate Matters. The feasibility of the merger remains under review.

PSO Rate Matters

2014 Oklahoma Base Rate Case

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

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

In June 2014, a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors was filed with the OCC. The parties to the stipulation recommended no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider would provide $7 million of revenues in 2014 and increase to $27 million in 2016. New depreciation rates are recommended for advanced metering investments and existing meters, also to be effective November 2014. Further, the stipulation recommends a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component. Additionally, the stipulation recommends recovery of regulatory assets for 2013 storms and regulatory case expenses. In July 2014, the Attorney General joined in the stipulation agreement. A hearing at the OCC was held in July 2014. An order is anticipated in the fourth quarter of 2014. If the OCC were to disallow any portion of this settlement agreement, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2% and adjusted the authorized annual increase in base rates to $92 million in March 2013.  In April 2014, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal to the Indiana Supreme Court related to the inclusion of a prepaid pension asset in rate base, which is approximately $7 million in annual revenues. In August 2014, the Indiana Supreme Court denied the appeal filed by the OUCC.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of September 30, 2014, I&M has incurred costs of $492 million related to the LCM Project, including AFUDC.


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

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project. In October 2014, the Michigan Court of Appeals issued an order that affirmed the MPSC decision in part, but reversed the portion of the MPSC decision related to certain costs. The order indicated that I&M could recover those costs in a future Michigan base case if they can show that the costs were reasonable and prudent.

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

Tanners Creek Plant

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

In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015. Upon the retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant.

In September 2014, a settlement agreement was approved by the MPSC that included the authorization for I&M to implement revised depreciation rates for Rockport Plant, Unit 1, effective upon the retirement date of the Tanners Creek Plant. Upon implementation of the revised depreciation rates, I&M is authorized to reduce customer rates through a credit rider until the revised rates for Rockport Plant, Unit 1 are included in base rates.

Transmission, Distribution and Storage System Improvement Charge (TDSIC)

In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan, from 2015 through 2021, for eligible transmission, distribution and storage system improvements. The initial estimated cost of the capital improvements and associated operation and maintenance expenses included in the TDSIC Plan of $787 million will be updated annually. The TDSIC Plan included distribution investments specific to the Indiana jurisdiction. The TDSIC Rider will allow the periodic adjustment of I&M's rates to provide for timely recovery of 80% of approved TDSIC Plan costs. I&M will defer the remaining 20% of approved TDSIC Plan costs to be recovered in I&M's next general rate case. I&M is not seeking a rate adjustment in this proceeding but is seeking approval of a TDSIC Rider rate adjustment mechanism for subsequent proceedings. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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5.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business.  In addition, their business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements.  The Commitments, Guarantees and Contingencies note within the 2013 Annual Report should be read in conjunction with this report.

GUARANTEES

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

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

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

AEP has two revolving credit facilities totaling $3.5 billion, under which up to $1.2 billion may be issued as letters of credit.  As of September 30, 2014, the maximum future payments for letters of credit issued under the revolving credit facilities were as follows:
Company
 
Amount
 
Maturity
 
 
(in thousands)
 
 
I&M
 
$
150

 
March 2015
OPCo
 
4,200

 
June 2015

The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows:
Company
 
Pollution
Control Bonds
 
Bilateral Letters
of Credit
 
Maturity of Bilateral
Letters of Credit
 
 
(in thousands)
 
 
APCo
 
$
229,650

 
$
232,293

 
March 2016 to March 2017 
I&M
 
77,000

 
77,886

 
March 2015

Guarantees of Third-Party Obligations – Affecting SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation.  As of September 30, 2014, SWEPCo has collected approximately $63 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $47 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed balance sheets.

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

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

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of September 30, 2014, there were no material liabilities recorded for any indemnifications.

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

Master Lease Agreements

The Registrant Subsidiaries lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.  As of September 30, 2014, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:
Company
 
Maximum
Potential Loss
 
 
(in thousands)
APCo
 
$
3,852

I&M
 
2,792

OPCo
 
4,549

PSO
 
1,812

SWEPCo
 
2,668


Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignments are accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $12 million and $14 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2014.

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


204



ENVIRONMENTAL CONTINGENCIES

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M
 
By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials.  The Registrant Subsidiaries currently incur costs to dispose of these substances safely.

In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M started remediation work in accordance with a plan approved by MDEQ.  In September 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As of September 30, 2014, I&M’s accrual for all of these sites is approximately $17 million.  As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation.  Management cannot predict the amount of additional cost, if any.

NUCLEAR CONTINGENCIES – AFFECTING I&M

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

OPERATIONAL CONTINGENCIES

Rockport Plant Litigation – Affecting I&M

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

Wage and Hours Lawsuit – Affecting PSO

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

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In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action.  Notice was given to all potential class members and an additional 43 individuals opted in to the class, bringing the plaintiff class to 79 current and former employees. Management will continue to defend the case. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Gavin Landfill Litigation – Affecting OPCo
In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill.  The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors.  Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims.  The plaintiffs seek compensatory and punitive damages, as well as medical monitoring.  In September 2014, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio.  That motion is pending.  Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.




206



6.  DISPOSITION AND IMPAIRMENTS

DISPOSITION

2013

Conesville Coal Preparation Facility – Affecting OPCo

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

IMPAIRMENTS

2013

Turk Plant – Affecting SWEPCo

In the third quarter of 2013, SWEPCo recorded a pretax write-off of $111 million in Asset Impairments and Other Related Charges on the statement of income related to AFUDC on the Turk Plant that was included in the Texas capital cost cap. See the "2012 Texas Base Rate Case" section of Note 4.

Muskingum River Plant, Unit 5 – Affecting OPCo

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


207



7.  BENEFIT PLANS

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

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2014 and 2013:

APCo
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2014

2013
 
2014
 
2013
 
(in thousands)
Service Cost
$
1,759

 
$
1,543

 
$
362

 
$
641

Interest Cost
7,406

 
6,916

 
3,197

 
3,363

Expected Return on Plan Assets
(8,482
)
 
(9,260
)
 
(4,634
)
 
(4,537
)
Amortization of Prior Service Cost (Credit)
49

 
49

 
(2,512
)
 
(2,512
)
Amortization of Net Actuarial Loss
4,149

 
6,256

 
1,145

 
3,063

Net Periodic Benefit Cost (Credit)
$
4,881

 
$
5,504

 
$
(2,442
)
 
$
18

 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Service Cost
$
5,277

 
$
4,628

 
$
1,086

 
$
1,924

Interest Cost
22,218

 
20,747

 
9,591

 
10,090

Expected Return on Plan Assets
(25,445
)
 
(27,780
)
 
(13,900
)
 
(13,610
)
Amortization of Prior Service Cost (Credit)
148

 
148

 
(7,537
)
 
(7,537
)
Amortization of Net Actuarial Loss
12,445

 
18,769

 
3,436

 
9,187

Net Periodic Benefit Cost (Credit)
$
14,643

 
$
16,512

 
$
(7,324
)
 
$
54



208



I&M
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Service Cost
$
2,517

 
$
2,183

 
$
486

 
$
804

Interest Cost
6,573

 
6,025

 
1,909

 
2,056

Expected Return on Plan Assets
(7,749
)
 
(8,206
)
 
(3,363
)
 
(3,295
)
Amortization of Prior Service Cost (Credit)
49

 
49

 
(2,355
)
 
(2,356
)
Amortization of Net Actuarial Loss
3,647

 
5,422

 
592

 
1,882

Net Periodic Benefit Cost (Credit)
$
5,037

 
$
5,473

 
$
(2,731
)
 
$
(909
)
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Service Cost
$
7,551

 
$
6,551

 
$
1,460

 
$
2,414

Interest Cost
19,720

 
18,075

 
5,728

 
6,166

Expected Return on Plan Assets
(23,245
)
 
(24,619
)
 
(10,090
)
 
(9,887
)
Amortization of Prior Service Cost (Credit)
146

 
146

 
(7,066
)
 
(7,066
)
Amortization of Net Actuarial Loss
10,939

 
16,266

 
1,776

 
5,645

Net Periodic Benefit Cost (Credit)
$
15,111

 
$
16,419

 
$
(8,192
)
 
$
(2,728
)

OPCo
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Service Cost
$
1,285

 
$
2,362

 
$
256

 
$
1,028

Interest Cost
5,527

 
10,268

 
1,900

 
4,100

Expected Return on Plan Assets
(6,607
)
 
(15,103
)
 
(3,379
)
 
(6,221
)
Amortization of Prior Service Cost (Credit)
40

 
71

 
(1,731
)
 
(3,219
)
Amortization of Net Actuarial Loss
3,105

 
9,287

 
595

 
3,761

Net Periodic Benefit Cost (Credit)
$
3,350

 
$
6,885

 
$
(2,359
)
 
$
(551
)
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Service Cost
$
3,855

 
$
7,107

 
$
769

 
$
3,627

Interest Cost
16,579

 
30,852

 
5,701

 
12,994

Expected Return on Plan Assets
(19,820
)
 
(45,386
)
 
(10,139
)
 
(18,698
)
Amortization of Prior Service Cost (Credit)
118

 
212

 
(5,192
)
 
(9,680
)
Amortization of Net Actuarial Loss
9,316

 
27,905

 
1,785

 
11,843

Net Periodic Benefit Cost (Credit)
$
10,048

 
$
20,690

 
$
(7,076
)
 
$
86



209



PSO
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Service Cost
$
1,301

 
$
1,391

 
$
209

 
$
343

Interest Cost
3,015

 
2,748

 
893

 
948

Expected Return on Plan Assets
(3,651
)
 
(3,919
)
 
(1,575
)
 
(1,522
)
Amortization of Prior Service Cost (Credit)
74

 
75

 
(1,072
)
 
(1,072
)
Amortization of Net Actuarial Loss
1,689

 
2,461

 
278

 
869

Net Periodic Benefit Cost (Credit)
$
2,428

 
$
2,756

 
$
(1,267
)
 
$
(434
)
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Service Cost
$
3,905

 
$
4,172

 
$
629

 
$
1,029

Interest Cost
9,043

 
8,245

 
2,680

 
2,844

Expected Return on Plan Assets
(10,953
)
 
(11,756
)
 
(4,725
)
 
(4,566
)
Amortization of Prior Service Cost (Credit)
222

 
223

 
(3,217
)
 
(3,217
)
Amortization of Net Actuarial Loss
5,065

 
7,383

 
832

 
2,607

Net Periodic Benefit Cost (Credit)
$
7,282

 
$
8,267

 
$
(3,801
)
 
$
(1,303
)

SWEPCo
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Service Cost
$
1,655

 
$
1,752

 
$
253

 
$
424

Interest Cost
3,163

 
2,864

 
998

 
1,075

Expected Return on Plan Assets
(3,857
)
 
(4,126
)
 
(1,754
)
 
(1,720
)
Amortization of Prior Service Cost (Credit)
87

 
87

 
(1,289
)
 
(1,289
)
Amortization of Net Actuarial Loss
1,762

 
2,553

 
309

 
982

Net Periodic Benefit Cost (Credit)
$
2,810

 
$
3,130

 
$
(1,483
)
 
$
(528
)
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Service Cost
$
4,964

 
$
5,258

 
$
759

 
$
1,270

Interest Cost
9,488

 
8,591

 
2,994

 
3,226

Expected Return on Plan Assets
(11,571
)
 
(12,381
)
 
(5,262
)
 
(5,160
)
Amortization of Prior Service Cost (Credit)
262

 
262

 
(3,867
)
 
(3,867
)
Amortization of Net Actuarial Loss
5,285

 
7,660

 
926

 
2,946

Net Periodic Benefit Cost (Credit)
$
8,428

 
$
9,390

 
$
(4,450
)
 
$
(1,585
)


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8.  BUSINESS SEGMENTS

The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business starting in 2014.  The Registrant Subsidiaries’ other activities are insignificant.  The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.


211



9.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

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

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


212



The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of September 30, 2014 and December 31, 2013:

Notional Volume of Derivative Instruments
September 30, 2014
Primary Risk
Exposure
 
Unit of
Measure
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
(in thousands)
Commodity:
 
 
 
 
 
 

 
 

 
 

 
 

Power
 
MWhs
 
50,109

 
36,076

 
23,709

 
6,486

 
7,918

Coal
 
Tons
 
465

 
889

 

 
250

 
542

Natural Gas
 
MMBtus
 
811

 
550

 

 

 

Heating Oil and Gasoline
 
Gallons
 
990

 
474

 
1,007

 
558

 
636

Interest Rate
 
USD
 
$
6,894

 
$
4,676

 
$

 
$

 
$


Notional Volume of Derivative Instruments
December 31, 2013
Primary Risk
Exposure
 
Unit of
Measure
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
(in thousands)
Commodity:
 
 
 
 
 
 

 
 

 
 

 
 

Power
 
MWhs
 
48,995

 
33,231

 
34,843

 
13,469

 
17,057

Coal
 
Tons
 
31

 
3,389

 

 
1,013

 
1,692

Natural Gas
 
MMBtus
 
2,477

 
1,680

 

 

 

Heating Oil and Gasoline
 
Gallons
 
1,089

 
521

 
1,108

 
614

 
699

Interest Rate
 
USD
 
$
12,720

 
$
8,627

 
$

 
$

 
$


Fair Value Hedging Strategies

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

Cash Flow Hedging Strategies

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

The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three and nine months ended September 30, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.


213



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

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

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

According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2014 and December 31, 2013 condensed balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:
 
 
September 30, 2014
 
December 31, 2013
Company
 
Cash Collateral
Received
Netted Against
Risk Management
Assets
 
Cash Collateral
Paid
Netted Against
Risk Management
Liabilities
 
Cash Collateral
Received
Netted Against
Risk Management
Assets
 
Cash Collateral
Paid
Netted Against
Risk Management
Liabilities
 
 
(in thousands)
APCo
 
$
441

 
$
261

 
$

 
$
2,993

I&M
 
154

 
151

 

 
2,030

OPCo
 

 
248

 

 

PSO
 

 
141

 

 
1

SWEPCo
 

 
160

 

 
3


214



The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of September 30, 2014 and December 31, 2013:

APCo

Fair Value of Derivative Instruments
September 30, 2014
 
 
Risk
Management
Contracts
 
Hedging Contracts
 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Interest Rate
and Foreign
Currency (a)
 
 
 
 
 
(in thousands)
Current Risk Management Assets
 
$
31,542

 
$

 
$

 
$
31,542

 
$
(9,723
)
 
$
21,819

Long-term Risk Management Assets
 
7,937

 

 

 
7,937

 
(1,436
)
 
6,501

Total Assets
 
39,479

 

 

 
39,479

 
(11,159
)
 
28,320

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
16,086

 

 

 
16,086

 
(9,715
)
 
6,371

Long-term Risk Management Liabilities
 
4,557

 

 

 
4,557

 
(1,264
)
 
3,293

Total Liabilities
 
20,643

 

 

 
20,643

 
(10,979
)
 
9,664

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
18,836

 
$

 
$

 
$
18,836

 
$
(180
)
 
$
18,656


APCo

Fair Value of Derivative Instruments
December 31, 2013
 
 
Risk
Management
Contracts
 
Hedging Contracts
 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Interest Rate
and Foreign
Currency (a)
 
 
 
 
 
(in thousands)
Current Risk Management Assets
 
$
46,431

 
$
389

 
$

 
$
46,820

 
$
(25,649
)
 
$
21,171

Long-term Risk Management Assets
 
20,948

 

 

 
20,948

 
(4,000
)
 
16,948

Total Assets
 
67,379

 
389

 

 
67,768

 
(29,649
)
 
38,119

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
37,010

 
313

 

 
37,323

 
(28,431
)
 
8,892

Long-term Risk Management Liabilities
 
14,452

 

 

 
14,452

 
(4,211
)
 
10,241

Total Liabilities
 
51,462

 
313

 

 
51,775

 
(32,642
)
 
19,133

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
15,917

 
$
76

 
$

 
$
15,993

 
$
2,993

 
$
18,986


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


215



I&M

Fair Value of Derivative Instruments
September 30, 2014
 
 
Risk
Management
Contracts
 
Hedging Contracts
 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Interest Rate
and Foreign
Currency (a)
 
 
 
 
 
(in thousands)
Current Risk Management Assets
 
$
23,289

 
$

 
$

 
$
23,289

 
$
(6,959
)
 
$
16,330

Long-term Risk Management Assets
 
5,383

 

 

 
5,383

 
(974
)
 
4,409

Total Assets
 
28,672

 

 

 
28,672

 
(7,933
)
 
20,739

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
10,705

 

 

 
10,705

 
(7,080
)
 
3,625

Long-term Risk Management Liabilities
 
2,882

 

 

 
2,882

 
(850
)
 
2,032

Total Liabilities
 
13,587

 

 

 
13,587

 
(7,930
)
 
5,657

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
15,085

 
$

 
$

 
$
15,085

 
$
(3
)
 
$
15,082


I&M

Fair Value of Derivative Instruments
December 31, 2013
 
 
Risk
Management
Contracts
 
Hedging Contracts
 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Interest Rate
and Foreign
Currency (a)
 
 
 
 
 
(in thousands)
Current Risk Management Assets
 
$
33,229

 
$
234

 
$

 
$
33,463

 
$
(18,075
)
 
$
15,388

Long-term Risk Management Assets
 
14,208

 

 

 
14,208

 
(2,713
)
 
11,495

Total Assets
 
47,437

 
234

 

 
47,671

 
(20,788
)
 
26,883

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
26,779

 
212

 

 
26,991

 
(19,962
)
 
7,029

Long-term Risk Management Liabilities
 
9,802

 

 

 
9,802

 
(2,856
)
 
6,946

Total Liabilities
 
36,581

 
212

 

 
36,793

 
(22,818
)
 
13,975

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
10,856

 
$
22

 
$

 
$
10,878

 
$
2,030

 
$
12,908


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


216



OPCo

Fair Value of Derivative Instruments
September 30, 2014
 
 
Risk
Management
Contracts
 
Hedging Contracts
 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Interest Rate
and Foreign
Currency (a)
 
 
 
 
 
(in thousands)
Current Risk Management Assets
 
$
7,889

 
$

 
$

 
$
7,889

 
$
28

 
$
7,917

Long-term Risk Management Assets
 

 

 

 

 
5

 
5

Total Assets
 
7,889

 

 

 
7,889

 
33

 
7,922

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
180

 

 

 
180

 
(180
)
 

Long-term Risk Management Liabilities
 
35

 

 

 
35

 
(35
)
 

Total Liabilities
 
215

 

 

 
215

 
(215
)
 

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
7,674

 
$

 
$

 
$
7,674

 
$
248

 
$
7,922


OPCo

Fair Value of Derivative Instruments
December 31, 2013
 
 
Risk
Management
Contracts
 
Hedging Contracts
 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Interest Rate
and Foreign
Currency (a)
 
 
 
 
 
(in thousands)
Current Risk Management Assets
 
$
3,269

 
$
162

 
$

 
$
3,431

 
$
(349
)
 
$
3,082

Long-term Risk Management Assets
 

 

 

 

 

 

Total Assets
 
3,269

 
162

 

 
3,431

 
(349
)
 
3,082

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
349

 

 

 
349

 
(349
)
 

Long-term Risk Management Liabilities
 

 

 

 

 

 

Total Liabilities
 
349

 

 

 
349

 
(349
)
 

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
2,920

 
$
162

 
$

 
$
3,082

 
$

 
$
3,082


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


217



PSO

Fair Value of Derivative Instruments
September 30, 2014
 
 
Risk
Management
Contracts
 
Hedging Contracts
 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Interest Rate
and Foreign
Currency (a)
 
 
 
 
 
(in thousands)
Current Risk Management Assets
 
$
595

 
$

 
$

 
$
595

 
$
(32
)
 
$
563

Long-term Risk Management Assets
 

 

 

 

 
3

 
3

Total Assets
 
595

 

 

 
595

 
(29
)
 
566

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
152

 

 

 
152

 
(152
)
 

Long-term Risk Management Liabilities
 
18

 

 

 
18

 
(18
)
 

Total Liabilities
 
170

 

 

 
170

 
(170
)
 

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
425

 
$

 
$

 
$
425

 
$
141

 
$
566


PSO

Fair Value of Derivative Instruments
December 31, 2013
 
 
Risk
Management
Contracts
 
Hedging Contracts
 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Interest Rate
and Foreign
Currency (a)
 
 
 
 
 
(in thousands)
Current Risk Management Assets
 
$
1,078

 
$
84

 
$

 
$
1,162

 
$
5

 
$
1,167

Long-term Risk Management Assets
 

 

 

 

 

 

Total Assets
 
1,078

 
84

 

 
1,162

 
5

 
1,167

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
81

 

 

 
81

 
4

 
85

Long-term Risk Management Liabilities
 

 

 

 

 

 

Total Liabilities
 
81

 

 

 
81

 
4

 
85

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
997

 
$
84

 
$

 
$
1,081

 
$
1

 
$
1,082


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


218



SWEPCo

Fair Value of Derivative Instruments
September 30, 2014
 
 
Risk
Management
Contracts
 
Hedging Contracts
 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Interest Rate
and Foreign
Currency (a)
 
 
 
 
 
(in thousands)
Current Risk Management Assets
 
$
468

 
$

 
$

 
$
468

 
$
(60
)
 
$
408

Long-term Risk Management Assets
 

 

 

 

 
3

 
3

Total Assets
 
468

 

 

 
468

 
(57
)
 
411

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
327

 

 

 
327

 
(196
)
 
131

Long-term Risk Management Liabilities
 
21

 

 

 
21

 
(21
)
 

Total Liabilities
 
348

 

 

 
348

 
(217
)
 
131

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
120

 
$

 
$

 
$
120

 
$
160

 
$
280


SWEPCo

Fair Value of Derivative Instruments
December 31, 2013
 
 
Risk
Management
Contracts
 
Hedging Contracts
 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Interest Rate
and Foreign
Currency (a)
 
 
 
 
 
(in thousands)
Current Risk Management Assets
 
$
1,233

 
$
97

 
$

 
$
1,330

 
$
(151
)
 
$
1,179

Long-term Risk Management Assets
 

 

 

 

 

 

Total Assets
 
1,233

 
97

 

 
1,330

 
(151
)
 
1,179

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
154

 

 

 
154

 
(154
)
 

Long-term Risk Management Liabilities
 

 

 

 

 

 

Total Liabilities
 
154

 

 

 
154

 
(154
)
 

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
1,079

 
$
97

 
$

 
$
1,176

 
$
3

 
$
1,179


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


219



The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and nine months ended September 30, 2014 and 2013:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 2014
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Electric Generation, Transmission and Distribution Revenues
 
$
1,231

 
$
2,988

 
$
41

 
$
45

 
$
74

Sales to AEP Affiliates
 

 
(196
)
 

 
196

 

Regulatory Assets (a)
 
(2,571
)
 
(471
)
 
(852
)
 
(109
)
 
(284
)
Regulatory Liabilities (a)
 
(3,606
)
 
(176
)
 
(1,555
)
 
120

 
(180
)
Total Gain (Loss) on Risk Management Contracts
 
$
(4,946
)
 
$
2,145

 
$
(2,366
)
 
$
252

 
$
(390
)

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 2013
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Electric Generation, Transmission and Distribution Revenues
 
$
746

 
$
1,742

 
$
66

 
$
25

 
$
51

Regulatory Assets (a)
 

 
(1,349
)
 

 
960

 
421

Regulatory Liabilities (a)
 
(950
)
 
(2,347
)
 
(1,264
)
 
18

 
130

Total Gain (Loss) on Risk Management Contracts
 
$
(204
)
 
$
(1,954
)
 
$
(1,198
)
 
$
1,003

 
$
602


Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 2014
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Electric Generation, Transmission and Distribution Revenues
 
$
7,262

 
$
10,467

 
$
97

 
$
172

 
$
18

Sales to AEP Affiliates
 

 
(717
)
 

 
717

 

Regulatory Assets (a)
 
(2,567
)
 
(471
)
 
(215
)
 
(119
)
 
(285
)
Regulatory Liabilities (a)
 
42,444

 
26,934

 
39,311

 
(69
)
 
119

Total Gain (Loss) on Risk Management Contracts
 
$
47,139

 
$
36,213

 
$
39,193

 
$
701

 
$
(148
)

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 2013
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Electric Generation, Transmission and Distribution Revenues
 
$
1,619

 
$
9,586

 
$
3,599

 
$
241

 
$
381

Regulatory Assets (a)
 

 
(1,648
)
 
(5,158
)
 
3,162

 
427

Regulatory Liabilities (a)
 
(1,160
)
 
(9,209
)
 
1,557

 
18

 
157

Total Gain (Loss) on Risk Management Contracts
 
$
459

 
$
(1,271
)
 
$
(2
)
 
$
3,421

 
$
965

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


220



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

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

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

Accounting for Fair Value Hedging Strategies

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

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. During the three and nine months ended September 30, 2014 and 2013, the Registrant Subsidiaries did not designate any fair value hedging strategies.

Accounting for Cash Flow Hedging Strategies

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

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2014, APCo and I&M designated power, coal and natural gas derivatives as cash flow hedges. During the three and nine months ended September 30, 2013, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. During the three and nine months ended September 30, 2013, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014.


221



The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2014 and 2013, I&M designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2014 and 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges.

During the three and nine months ended September 30, 2014 and 2013, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2014 and 2013, see Note 3.


222



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

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
September 30, 2014
 
 
Hedging Assets (a)
 
Hedging Liabilities (a)
 
AOCI Gain (Loss) Net of Tax
Company
 
Commodity
 
Interest Rate
and Foreign
Currency
 
Commodity
 
Interest Rate
and Foreign
Currency
 
Commodity
 
Interest Rate
and Foreign
Currency
 
 
(in thousands)
APCo
 
$

 
$

 
$

 
$

 
$

 
$
3,766

I&M
 

 

 

 

 

 
(14,745
)
OPCo
 

 

 

 

 

 
5,945

PSO
 

 

 

 

 

 
5,132

SWEPCo
 

 

 

 

 

 
(11,602
)
 
 
Expected to be Reclassified to
Net Income During the Next
Twelve Months
 
 
Company
 
Commodity
 
Interest Rate
and Foreign
Currency
 
Maximum Term for
Exposure to
Variability of Future
Cash Flows
 
 
(in thousands)
 
(in months)
APCo
 
$

 
$
(38
)
 
0
I&M
 

 
(1,140
)
 
0
OPCo
 

 
1,372

 
0
PSO
 

 
759

 
0
SWEPCo
 

 
(2,132
)
 
0

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 2013
 
 
Hedging Assets (a)
 
Hedging Liabilities (a)
 
AOCI Gain (Loss) Net of Tax
Company
 
Commodity
 
Interest Rate
and Foreign
Currency
 
Commodity
 
Interest Rate
and Foreign
Currency
 
Commodity
 
Interest Rate
and Foreign
Currency
 
 
(in thousands)
APCo
 
$
363

 
$

 
$
287

 
$

 
$
94

 
$
3,090

I&M
 
216

 

 
194

 

 
46

 
(15,976
)
OPCo
 
162

 

 

 

 
105

 
6,974

PSO
 
84

 

 

 

 
57

 
5,701

SWEPCo
 
97

 

 

 

 
66

 
(13,304
)
 
 
Expected to be Reclassified to
Net Income During the Next
Twelve Months
Company
 
Commodity
 
Interest Rate
and Foreign
Currency
 
 
(in thousands)
APCo
 
$
94

 
$
(806
)
I&M
 
46

 
(1,568
)
OPCo
 
105

 
1,363

PSO
 
57

 
759

SWEPCo
 
66

 
(2,267
)

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


223



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

Credit Risk

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

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

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries’ fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of September 30, 2014 and December 31, 2013:
 
 
September 30, 2014
Company
 
Liabilities for
Derivative Contracts
with Credit
Downgrade Triggers
 
Amount of Collateral the
Registrant Subsidiaries
Would Have Been
Required to Post
 
Amount
Attributable to
RTO and ISO
Activities
 
 
(in thousands)
APCo
 
$
157

 
$
2,721

 
$
2,697

I&M
 
107

 
1,842

 
1,829

OPCo
 

 

 

PSO
 
49

 
4,123

 

SWEPCo
 
60

 
176

 

 
 
December 31, 2013
Company
 
Liabilities for
Derivative Contracts
with Credit
Downgrade Triggers
 
Amount of Collateral the
Registrant Subsidiaries
Would Have Been
Required to Post
 
Amount
Attributable to
RTO and ISO
Activities
 
 
(in thousands)
APCo
 
$
575

 
$
2,747

 
$
2,539

I&M
 
390

 
1,863

 
1,722

OPCo
 
349

 

 

PSO
 

 
2,930

 
410

SWEPCo
 

 
713

 
519


224




In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of September 30, 2014 and December 31, 2013:
 
 
September 30, 2014
Company
 
Liabilities for
Contracts with Cross
Default Provisions
Prior to Contractual
Netting Arrangements
 
Amount of Cash
Collateral Posted
 
Additional
Settlement
Liability if Cross
Default Provision
is Triggered
 
 
(in thousands)
APCo
 
$
7,769

 
$

 
$
7,219

I&M
 
5,269

 

 
4,897

OPCo
 

 

 

PSO
 

 

 

SWEPCo
 

 

 

 
 
December 31, 2013
Company
 
Liabilities for
Contracts with Cross
Default Provisions
Prior to Contractual
Netting Arrangements
 
Amount of Cash
Collateral Posted
 
Additional
Settlement
Liability if Cross
Default Provision
is Triggered
 
 
(in thousands)
APCo
 
$
19,648

 
$

 
$
18,568

I&M
 
13,326

 

 
12,594

OPCo
 

 

 

PSO
 
3

 

 
3

SWEPCo
 
3

 

 
3



225



10.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

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

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

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

Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds.  Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in

226



yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

Fair Value Measurements of Long-term Debt

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

The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of September 30, 2014 and December 31, 2013 are summarized in the following table:
 
 
September 30, 2014
 
December 31, 2013
Company
 
Book Value
 
Fair Value
 
Book Value
 
Fair Value
 
 
(in thousands)
APCo
 
$
3,980,107

 
$
4,642,320

 
$
4,194,357

 
$
4,587,079

I&M
 
1,948,931

 
2,166,248

 
2,039,016

 
2,174,891

OPCo
 
2,297,004

 
2,688,426

 
2,735,175

 
3,007,191

PSO
 
1,041,056

 
1,205,687

 
999,810

 
1,111,149

SWEPCo
 
2,140,348

 
2,401,635

 
2,043,332

 
2,214,730


Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

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

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

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

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

227




The following is a summary of nuclear trust fund investments as of September 30, 2014 and December 31, 2013:
 
September 30, 2014
 
December 31, 2013
 
Estimated Fair
Value
 
Gross Unrealized
Gains
 
Other-Than-Temporary
Impairments
 
Estimated Fair
Value
 
Gross Unrealized
Gains
 
Other-Than-Temporary Impairments
 
(in thousands)
Cash and Cash Equivalents
$
13,188

 
$

 
$

 
$
18,804

 
$

 
$

Fixed Income Securities:
 

 
 

 
 

 
 

 
 

 
 

United States Government
609,441

 
35,262

 
(2,941
)
 
608,875

 
26,114

 
(3,824
)
Corporate Debt
46,409

 
3,630

 
(1,046
)
 
36,782

 
2,450

 
(1,123
)
State and Local Government
285,496

 
1,309

 
(215
)
 
254,638

 
748

 
(370
)
Subtotal Fixed Income Securities
941,346

 
40,201

 
(4,202
)
 
900,295

 
29,312

 
(5,317
)
Equity Securities - Domestic
1,065,714

 
544,995

 
(79,329
)
 
1,012,511

 
505,538

 
(81,677
)
Spent Nuclear Fuel and Decommissioning Trusts
$
2,020,248

 
$
585,196

 
$
(83,531
)
 
$
1,931,610

 
$
534,850

 
$
(86,994
)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2014 and 2013:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2014
 
2013
 
2014
 
2013
 
 
(in thousands)
Proceeds from Investment Sales
 
$
263,738

 
$
249,314

 
$
746,272

 
$
635,256

Purchases of Investments
 
280,626

 
263,958

 
789,461

 
675,727

Gross Realized Gains on Investment Sales
 
7,617

 
4,113

 
24,835

 
16,011

Gross Realized Losses on Investment Sales
 
1,739

 
2,147

 
10,447

 
11,859


The adjusted cost of fixed income securities was $901 million and $872 million as of September 30, 2014 and December 31, 2013, respectively.  The adjusted cost of equity securities was $521 million and $506 million as of September 30, 2014 and December 31, 2013, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2014 was as follows:
 
Fair Value of Fixed Income Securities
 
(in thousands)
Within 1 year
$
103,652

1 year – 5 years
376,783

5 years – 10 years
198,064

After 10 years
262,847

Total
$
941,346



228



Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2014 and December 31, 2013.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in management’s valuation techniques.

APCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2014
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash for Securitized Funding (a)
 
$
8,071

 
$

 
$

 
$
45

 
$
8,116

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
191

 
20,498

 
17,784

 
(10,153
)
 
28,320

 
 
 
 
 
 
 
 
 
 
 
Total Assets:
 
$
8,262

 
$
20,498

 
$
17,784

 
$
(10,108
)
 
$
36,436

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$
186

 
$
17,679

 
$
1,772

 
$
(9,973
)
 
$
9,664


APCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash for Securitized Funding (a)
 
$
2,714

 
$

 
$

 
$
36

 
$
2,750

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
827

 
54,448

 
12,097

 
(29,616
)
 
37,756

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (b)
 

 
389

 

 
(26
)
 
363

Total Risk Management Assets
 
827

 
54,837

 
12,097

 
(29,642
)
 
38,119

 
 
 
 
 
 
 
 
 
 
 
Total Assets:
 
$
3,541

 
$
54,837

 
$
12,097

 
$
(29,606
)
 
$
40,869

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$
700

 
$
49,220

 
$
1,535

 
$
(32,609
)
 
$
18,846

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (b)
 

 
313

 

 
(26
)
 
287

Total Risk Management Liabilities
 
$
700

 
$
49,533

 
$
1,535

 
$
(32,635
)
 
$
19,133


229



I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2014
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$
129

 
$
14,516

 
$
13,344

 
$
(7,250
)
 
$
20,739

 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 

 
 

 
 

 
 

 
 

Cash and Cash Equivalents (d)
 
4,470

 

 

 
8,718

 
13,188

Fixed Income Securities:
 
 

 
 

 
 

 
 

 
 

United States Government
 

 
609,441

 

 

 
609,441

Corporate Debt
 

 
46,409

 

 

 
46,409

State and Local Government
 

 
285,496

 

 

 
285,496

Subtotal Fixed Income Securities
 

 
941,346

 

 

 
941,346

Equity Securities - Domestic (e)
 
1,065,714

 

 

 

 
1,065,714

Total Spent Nuclear Fuel and Decommissioning Trusts
 
1,070,184

 
941,346

 

 
8,718

 
2,020,248

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
1,070,313

 
$
955,862

 
$
13,344

 
$
1,468

 
$
2,040,987

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$
125

 
$
11,577

 
$
1,202

 
$
(7,247
)
 
$
5,657



230



I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$
561

 
$
38,667

 
$
8,205

 
$
(20,766
)
 
$
26,667

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (b)
 

 
234

 

 
(18
)
 
216

Total Risk Management Assets
 
561

 
38,901

 
8,205

 
(20,784
)
 
26,883

 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 

 
 

 
 

 
 

 
 

Cash and Cash Equivalents (d)
 
8,082

 

 

 
10,722

 
18,804

Fixed Income Securities:
 
 

 
 

 
 

 
 

 


United States Government
 

 
608,875

 

 

 
608,875

Corporate Debt
 

 
36,782

 

 

 
36,782

State and Local Government
 

 
254,638

 

 

 
254,638

Subtotal Fixed Income Securities
 

 
900,295

 

 

 
900,295

Equity Securities - Domestic (e)
 
1,012,511

 

 

 

 
1,012,511

Total Spent Nuclear Fuel and Decommissioning Trusts
 
1,020,593

 
900,295

 

 
10,722

 
1,931,610

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
1,021,154

 
$
939,196

 
$
8,205

 
$
(10,062
)
 
$
1,958,493

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$
475

 
$
35,061

 
$
1,041

 
$
(22,796
)
 
$
13,781

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (b)
 

 
212

 

 
(18
)
 
194

Total Risk Management Liabilities
 
$
475

 
$
35,273

 
$
1,041

 
$
(22,814
)
 
$
13,975




231



OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2014
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash for Securitized Funding (a)
 
$
17,734

 
$

 
$

 
$
22

 
$
17,756

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 

 

 
7,889

 
33

 
7,922

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
17,734

 
$

 
$
7,889

 
$
55

 
$
25,678

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (b) (c)
 
$

 
$
215

 
$

 
$
(215
)
 
$


OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash for Securitized Funding (a)
 
$
19,387

 
$

 
$

 
$
12

 
$
19,399

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 

 

 
3,269

 
(349
)
 
2,920

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (b)
 

 
162

 

 

 
162

Total Risk Management Assets
 

 
162

 
3,269

 
(349
)
 
3,082

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
19,387

 
$
162

 
$
3,269

 
$
(337
)
 
$
22,481

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$

 
$

 
$
349

 
$
(349
)
 
$



232



PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2014
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$

 
$
232

 
$
383

 
$
(49
)
 
$
566

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$

 
$
141

 
$
49

 
$
(190
)
 
$


PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$

 
$
1,078

 
$

 
$
5

 
$
1,083

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (b)
 

 
84

 

 

 
84

Total Risk Management Assets
 
$

 
$
1,162

 
$

 
$
5

 
$
1,167

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$

 
$
81

 
$

 
$
4

 
$
85



233



SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2014
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
$
21,611

 
$

 
$

 
$
2,375

 
$
23,986

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 

 
3

 
468

 
(60
)
 
411

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
21,611

 
$
3

 
$
468

 
$
2,315

 
$
24,397

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$

 
$
291

 
$
60

 
$
(220
)
 
$
131


SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
$
15,871

 
$

 
$

 
$
1,370

 
$
17,241

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 

 
1,233

 

 
(151
)
 
1,082

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (b)
 

 
97

 

 

 
97

Total Risk Management Assets
 

 
1,330

 

 
(151
)

1,179

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
15,871

 
$
1,330

 
$

 
$
1,219

 
$
18,420

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$

 
$
154

 
$

 
$
(154
)
 
$


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

There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2014 and 2013.

234



The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy for the Registrant Subsidiaries:
Three Months Ended September 30, 2014
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of June 30, 2014
 
$
18,394

 
$
12,923

 
$
9,300

 
$
(3
)
 
$
(3
)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
(5,629
)
 
(3,832
)
 
(3,639
)
 
2

 
2

Purchases, Issuances and Settlements (c)
 
(1,560
)
 
(1,244
)
 
(637
)
 

 

Transfers into Level 3 (d) (e)
 
(6
)
 
(4
)
 

 

 

Transfers out of Level 3 (e) (f)
 
(30
)
 
(20
)
 

 

 

Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
4,843

 
4,319

 
2,865

 
335

 
409

Balance as of September 30, 2014
 
$
16,012

 
$
12,142

 
$
7,889

 
$
334

 
$
408

Three Months Ended September 30, 2013
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of June 30, 2013
 
$
12,976

 
$
8,967

 
$
18,347

 
$

 
$

Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
(1,200
)
 
(754
)
 
(1,616
)
 

 

Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
 

 

 
(89
)
 

 

Purchases, Issuances and Settlements (c)
 
(1,058
)
 
(757
)
 
(1,504
)
 

 

Transfers into Level 3 (d) (e)
 
13

 
9

 
18

 

 

Transfers out of Level 3 (e) (f)
 
(15
)
 
(11
)
 
(21
)
 

 

Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
195

 
(275
)
 
(164
)
 

 

Balance as of September 30, 2013
 
$
10,911

 
$
7,179

 
$
14,971

 
$

 
$

Nine Months Ended September 30, 2014
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of December 31, 2013
 
$
10,562

 
$
7,164

 
$
2,920

 
$

 
$

Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
29,467

 
18,438

 
30,768

 

 

Purchases, Issuances and Settlements (c)
 
(32,213
)
 
(20,301
)
 
(33,688
)
 

 

Transfers into Level 3 (d) (e)
 
(3,648
)
 
(2,475
)
 

 

 

Transfers out of Level 3 (e) (f)
 
(32
)
 
(22
)
 

 

 

Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
11,876

 
9,338

 
7,889

 
334

 
408

Balance as of September 30, 2014
 
$
16,012

 
$
12,142

 
$
7,889

 
$
334

 
$
408


235



Nine Months Ended September 30, 2013
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of December 31, 2012
 
$
10,979

 
$
7,541

 
$
15,429

 
$

 
$

Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
(3,450
)
 
(2,386
)
 
(4,879
)
 

 

Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
 

 

 
351

 

 

Purchases, Issuances and Settlements (c)
 
1,712

 
1,213

 
2,463

 

 

Transfers into Level 3 (d) (e)
 
961

 
661

 
1,353

 

 

Transfers out of Level 3 (e) (f)
 
(925
)
 
(637
)
 
(1,303
)
 

 

Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
1,634

 
787

 
1,557

 

 

Balance as of September 30, 2013
 
$
10,911

 
$
7,179

 
$
14,971

 
$

 
$


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

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions for the Registrant Subsidiaries as of September 30, 2014 and December 31, 2013:

Significant Unobservable Inputs
September 30, 2014
APCo
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
$
4,873

 
$
1,615

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
12.55

 
$
80.70

 
$
41.68

FTRs
12,911

 
157

 
Discounted Cash Flow 
 
Forward Market Price 
 
(14.63
)
 
15.47

 
1.38

Total
$
17,784

 
$
1,772

 
 
 
 
 
 

 
 

 
 

Significant Unobservable Inputs
December 31, 2013
APCo
 
 
 
 
 
 
 
Significant
 
 
 
 
 
Fair Value
 
Valuation
 
Unobservable
 
Forward Price Range
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
(in thousands)
 
 
 
 
 
 
 
 
Energy Contracts
$
9,359

 
$
960

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
13.04

 
$
80.50

FTRs
2,738

 
575

 
Discounted Cash Flow 
 
Forward Market Price 
 
(5.10
)
 
10.44

Total
$
12,097

 
$
1,535

 
 
 
 
 
 

 
 


236



Significant Unobservable Inputs
September 30, 2014
I&M
 
 
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
$
3,496

 
$
1,095

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
12.55

 
$
80.70

 
$
41.68

FTRs
9,848

 
107

 
Discounted Cash Flow 
 
Forward Market Price 
 
(14.63
)
 
15.47

 
1.38

Total
$
13,344

 
$
1,202

 
 
 
 
 
 

 
 

 
 

Significant Unobservable Inputs
December 31, 2013
I&M
 
 
 
 
 
 
 
Significant
 
 
 
 
 
Fair Value
 
Valuation
 
Unobservable
 
Forward Price Range
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
(in thousands)
 
 
 
 
 
 
 
 
Energy Contracts
$
6,348

 
$
651

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
13.04

 
$
80.50

FTRs
1,857

 
390

 
Discounted Cash Flow 
 
Forward Market Price 
 
(5.10
)
 
10.44

Total
$
8,205

 
$
1,041

 
 
 
 
 
 

 
 


Significant Unobservable Inputs
September 30, 2014
OPCo
 
 
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
FTRs
$
7,889

 
$

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
(14.63
)
 
$
15.47

 
$
1.38


Significant Unobservable Inputs
December 31, 2013
OPCo
 
 
 
 
 
 
 
Significant
 
 
 
 
 
Fair Value
 
Valuation
 
Unobservable
 
Forward Price Range
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
(in thousands)
 
 
 
 
 
 
 
 
FTRs
$
3,269

 
$
349

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
(5.10
)
 
$
10.44



237



Significant Unobservable Inputs
September 30, 2014
PSO
 
 
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
FTRs
$
383

 
$
49

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
(14.63
)
 
$
15.47

 
$
1.38


Significant Unobservable Inputs
September 30, 2014
SWEPCo
 
 
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
FTRs
$
468

 
$
60

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
(14.63
)
 
$
15.47

 
$
1.38


(a)
Represents market prices in dollars per MWh.

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

Sensitivity of Fair Value Measurements
September 30, 2014
Significant Unobservable Input
 
Position
 
Change in Input
 
Impact on Fair Value
Measurement
Forward Market Price
 
Buy
 
Increase (Decrease)
 
Higher (Lower)
Forward Market Price
 
Sell
 
Increase (Decrease)
 
Lower (Higher)


238



11.  INCOME TAXES

AEP System Tax Allocation Agreement

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

Federal and State Income Tax Audit Status

The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013.  The IRS examination of years 2011 and 2012 started in April 2014. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions.  Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.

The Registrant Subsidiaries file income tax returns in various state and local jurisdictions.  These taxing authorities routinely examine the tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions.  However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities.  Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income.  The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009.



239



12.  FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2014 are shown in the tables below:
Company
 
Type of Debt
 
Principal Amount (a)
 
Interest Rate
 
Due Date
Issuances:
 
 
 
(in thousands)
 
(%)
 
 
APCo
 
Senior Unsecured Notes
 
$
300,000

 
4.40
 
2044
I&M
 
Pollution Control Bonds
 
100,000

 
1.75
 
2018
PSO
 
Other Long-term Debt
 
75,000

 
Variable
 
2016
SWEPCo
 
Other Long-term Debt
 
100,000

 
Variable
 
2017

(a)
Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Company
 
Type of Debt
 
 Principal Amount Paid
 
Interest Rate
 
Due Date
Retirements and Principal Payments:
 
 
 
(in thousands)
 
(%)
 
 
APCo
 
Land Note
 
$
24

 
13.718
 
2026
APCo
 
Securitization Bonds
 
12,678

 
2.01
 
2024
APCo
 
Senior Unsecured Notes
 
200,000

 
4.95
 
2015
APCo
 
Other Long-term Debt
 
300,000

 
Variable
 
2015
I&M
 
Notes Payable
 
29,275

 
Variable
 
2017
I&M
 
Notes Payable
 
22,332

 
Variable
 
2016
I&M
 
Notes Payable
 
15,472

 
Variable
 
2016
I&M
 
Notes Payable
 
10,716

 
2.12
 
2016
I&M
 
Notes Payable
 
4,402

 
4.00
 
2014
I&M
 
Other Long-term Debt
 
7,563

 
Variable
 
2015
I&M
 
Other Long-term Debt
 
790

 
6.00
 
2025
I&M
 
Pollution Control Bonds
 
100,000

 
6.25
 
2014
OPCo
 
Other Long-term Debt
 
67

 
1.149
 
2028
OPCo
 
Pollution Control Bonds
 
39,130

 
2.875
 
2014
OPCo
 
Pollution Control Bonds
 
79,450

 
3.25
 
2014
OPCo
 
Pollution Control Bonds
 
60,000

 
3.875
 
2014
OPCo
 
Securitization Bonds
 
34,936

 
0.958
 
2018
OPCo
 
Senior Unsecured Notes
 
225,000

 
4.85
 
2014
PSO
 
Other Long-term Debt
 
310

 
3.00
 
2027
PSO
 
Pollution Control Bonds
 
33,700

 
5.25
 
2014
SWEPCo
 
Notes Payable
 
3,250

 
4.58
 
2032

In October 2014, APCo remarketed $100 million of 1.625% Pollution Control Bonds due in 2018.

In October 2014, I&M retired $5 million of Notes Payable related to DCC Fuel.

As of September 30, 2014, trustees held on behalf of I&M and OPCo, $40 million and $395 million, respectively, of their reacquired Pollution Control Bonds.


240



Dividend Restrictions

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

Federal Power Act

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

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

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

Leverage Restrictions

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

Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries.  The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC.  The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2014 and December 31, 2013 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ condensed balance sheets.  The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2014 are described in the following table:
Company
 
Maximum
Borrowings
from the
Utility
Money Pool
 
Maximum
Loans to the
Utility
Money Pool
 
Average
Borrowings
from the
Utility
Money Pool
 
Average
Loans to the
Utility
Money Pool
 
Net Loans to
(Borrowings from)
the Utility Money
Pool as of
September 30, 2014
 
Authorized
Short-term
Borrowing
Limit
 
 
(in thousands)
APCo
 
$
44,215

 
$
542,186

 
$
14,038

 
$
122,105

 
$
70,090

 
$
600,000

I&M
 
130,128

 
158,857

 
59,863

 
47,695

 
(82,400
)
 
500,000

OPCo
 
120,264

 
405,350

 
34,841

 
82,518

 
23,745

 
400,000

PSO
 
176,950

 

 
93,679

 

 
(100,867
)
 
300,000

SWEPCo
 
153,503

 
49,869

 
82,953

 
22,408

 
(6,329
)
 
350,000



241



The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
Maximum Interest Rate
 
0.33
%
 
0.43
%
Minimum Interest Rate
 
0.24
%
 
0.28
%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2014 and 2013 are summarized for all Registrant Subsidiaries in the following table:
 
 
Average Interest Rate
for Funds Borrowed
from the Utility Money Pool for
 
Average Interest Rate
for Funds Loaned
to the Utility Money Pool for
 
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
Company
 
2014
 
2013
 
2014
 
2013
APCo
 
0.26
%
 
0.33
%
 
0.28
%
 
0.34
%
I&M
 
0.27
%
 
0.36
%
 
0.30
%
 
0.33
%
OPCo
 
0.27
%
 
0.34
%
 
0.29
%
 
0.32
%
PSO
 
0.27
%
 
0.34
%
 
%
 
0.32
%
SWEPCo
 
0.28
%
 
0.33
%
 
0.27
%
 
0.36
%

Credit Facilities

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

Sale of Receivables – AEP Credit

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

AEP Credit's receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables.  The agreement was increased in June 2014 from $700 million and expires in June 2016.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2014 and December 31, 2013 was as follows:
 
 
September 30,
 
December 31,
Company
 
2014
 
2013
 
 
(in thousands)
APCo
 
$
134,986

 
$
156,599

I&M
 
136,897

 
139,257

OPCo
 
345,545

 
324,287

PSO
 
156,781

 
115,260

SWEPCo
 
179,687

 
149,337



242



The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Company
 
2014
 
2013
 
2014
 
2013
 
 
(in thousands)
APCo
 
$
2,166

 
$
1,575

 
$
6,626

 
$
4,590

I&M
 
2,011

 
1,762

 
5,836

 
4,744

OPCo
 
7,213

 
5,076

 
21,358

 
14,440

PSO
 
1,745

 
1,549

 
4,417

 
4,314

SWEPCo
 
1,890

 
1,649

 
5,035

 
4,413


The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Company
 
2014
 
2013
 
2014
 
2013
 
 
(in thousands)
APCo
 
$
354,406

 
$
340,438

 
$
1,137,564

 
$
1,081,615

I&M
 
372,422

 
384,316

 
1,132,603

 
1,097,563

OPCo
 
668,112

 
658,829

 
1,980,764

 
2,017,746

PSO
 
398,567

 
382,167

 
1,014,320

 
944,062

SWEPCo
 
466,828

 
450,294

 
1,278,325

 
1,171,306



243



13.  VARIABLE INTEREST ENTITIES

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

SWEPCo is the primary beneficiary of Sabine.  I&M is the primary beneficiary of DCC Fuel.  OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding.  APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding.  In addition, the Registrant Subsidiaries have not provided material financial or other support to any of these entities that was not previously contractually required. SWEPCo holds a significant variable interest in DHLC.  Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC.  I&M holds a significant variable interest in AEGCo. In 2013, I&M and OPCo each held a significant variable interest in AEGCo.
 
Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the three months ended September 30, 2014 and 2013 were $41 million and $41 million, respectively, and for the nine months ended September 30, 2014 and 2013 were $121 million and $125 million, respectively.  See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets.

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

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
September 30, 2014 and December 31, 2013
(in thousands)
 
 
Sabine
ASSETS
 
2014
 
2013
Current Assets
 
$
61,855

 
$
66,478

Net Property, Plant and Equipment
 
148,098

 
157,274

Other Noncurrent Assets
 
51,098

 
51,211

Total Assets
 
$
261,051

 
$
274,963

 
 
 
 
 
LIABILITIES AND EQUITY
 
 

 
 

Current Liabilities
 
$
30,592

 
$
32,812

Noncurrent Liabilities
 
230,128

 
241,673

Equity
 
331

 
478

Total Liabilities and Equity
 
$
261,051

 
$
274,963


244




I&M has nuclear fuel lease agreements with DCC Fuel II LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI LLC (collectively DCC Fuel).  DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the leases for the three months ended September 30, 2014 and 2013 were $28 million and $32 million, respectively, and for the nine months ended September 30, 2014 and 2013 were $84 million and $96 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months.  Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  In October 2013, the lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC.  See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s condensed balance sheets.

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

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
September 30, 2014 and December 31, 2013
(in thousands)
 
 
DCC Fuel
ASSETS
 
2014
 
2013
Current Assets
 
$
68,819

 
$
117,762

Net Property, Plant and Equipment
 
73,468

 
156,820

Other Noncurrent Assets
 
26,843

 
60,450

Total Assets
 
$
169,130

 
$
335,032

 
 
 
 
 
LIABILITIES AND EQUITY
 
 

 
 

Current Liabilities
 
$
64,754

 
$
107,815

Noncurrent Liabilities
 
104,376

 
227,217

Total Liabilities and Equity
 
$
169,130

 
$
335,032


Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property.  Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant.  Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding.  The securitized bonds totaled $232 million and $267 million as of September 30, 2014 and December 31, 2013, respectively, and are included in current and long-term debt on the condensed balance sheets.  Ohio Phase-in-Recovery Funding has securitized assets of $116 million and $132 million as of September 30, 2014 and December 31, 2013, respectively, which are presented separately on the face of the condensed balance sheets.  The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO.  In August 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to OPCo or any other AEP entity.  OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs.


245



The balances below represent the assets and liabilities of Ohio Phase-in-Recovery Funding that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

OHIO POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
September 30, 2014 and December 31, 2013
(in thousands)
 

Ohio
Phase-In Recovery
Funding
ASSETS

2014

2013
Current Assets

$
21,657


$
23,198

Other Noncurrent Assets (a)

221,070


251,409

Total Assets

$
242,727


$
274,607

 

 




LIABILITIES AND EQUITY

 




Current Liabilities

$
46,263


$
36,470

Noncurrent Liabilities

195,127


236,800

Equity

1,337


1,337

Total Liabilities and Equity

$
242,727


$
274,607

(a)
Includes an intercompany item eliminated in consolidation as of September 30, 2014 and December 31, 2013 of $102 million and $116 million, respectively.

Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance.  Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant.  Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding.  The securitized bonds totaled $368 million and $380 million as of September 30, 2014 and December 31, 2013, respectively, and are included in current and long term debt on the condensed balance sheets.  Appalachian Consumer Rate Relief Funding has securitized assets of $356 million and $369 million as of September 30, 2014 and December 31, 2013, respectively, which are presented separately on the face of the condensed balance sheets.  The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC.  In November 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to APCo or any other AEP entity.  APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs.


246



The balances below represent the assets and liabilities of Appalachian Consumer Rate Relief Funding that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
September 30, 2014 and December 31, 2013
(in thousands)
 
 
Appalachian Consumer Rate
Relief Funding
ASSETS
 
2014
 
2013
Current Assets
 
$
10,298

 
$
5,891

Other Noncurrent Assets (a)
 
363,805

 
378,029

Total Assets
 
$
374,103

 
$
383,920

 
 
 
 
 
LIABILITIES AND EQUITY
 
 

 
 
Current Liabilities
 
$
24,238

 
$
14,000

Noncurrent Liabilities
 
347,963

 
368,018

Equity
 
1,902

 
1,902

Total Liabilities and Equity
 
$
374,103

 
$
383,920


(a)
Includes an intercompany item eliminated in consolidation as of September 30, 2014 and December 31, 2013 of $4 million and $4 million, respectively.

DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and voting rights equally.  Each entity guarantees 50% of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  SWEPCo’s total billings from DHLC for the three months ended September 30, 2014 and 2013 were $24 million and $21 million, respectively, and for the nine months ended September 30, 2014 and 2013 were $31 million and $53 million, respectively.  SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC.  SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheets.

SWEPCo’s investment in DHLC was:
 
 
September 30, 2014
 
December 31, 2013
 
 
As Reported on
the Balance Sheet
 
Maximum
Exposure
 
As Reported on
the Balance Sheet
 
Maximum
Exposure
 
 
(in thousands)
Capital Contribution from SWEPCo
 
$
7,643

 
$
7,643

 
$
7,643

 
$
7,643

Retained Earnings
 
3,061

 
3,061

 
1,600

 
1,600

SWEPCo's Guarantee of Debt
 

 
113,290

 

 
61,348

 
 
 
 
 
 
 
 
 
Total Investment in DHLC
 
$
10,704

 
$
123,994

 
$
9,243

 
$
70,591


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

247



operations.  AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure.  However, AEP subsidiaries do not have control over AEPSC.  AEPSC is consolidated by AEP.  In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

Total AEPSC billings to the Registrant Subsidiaries were as follows:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Company
 
2014
 
2013
 
2014
 
2013
 
 
(in thousands)
APCo
 
$
50,143

 
$
39,779

 
$
154,239

 
$
120,315

I&M
 
30,613

 
25,988

 
92,686

 
82,192

OPCo
 
41,212

 
58,528

 
120,696

 
169,949

PSO
 
24,317

 
19,535

 
71,646

 
57,504

SWEPCo
 
32,787

 
28,431

 
98,528

 
85,506


The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows:
 
 
September 30, 2014
 
December 31, 2013
Company
 
As Reported on the
Balance Sheet
 
Maximum
Exposure
 
As Reported on the
Balance Sheet
 
Maximum
Exposure
 
 
(in thousands)
APCo
 
$
15,634

 
$
15,634

 
$
20,191

 
$
20,191

I&M
 
9,086

 
9,086

 
12,864

 
12,864

OPCo
 
12,553

 
12,553

 
31,425

 
31,425

PSO
 
7,636

 
7,636

 
10,596

 
10,596

SWEPCo
 
8,718

 
8,718

 
13,520

 
13,520


AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP.  AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station.  AEGCo sells all the output from the Rockport Plant to I&M and KPCo.   AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014.  AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo.  I&M is considered to have a significant interest in AEGCo due to these transactions.  I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations.  In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP.  For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 12 in the 2013 Annual Report.

Total billings from AEGCo were as follows:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Company
 
2014
 
2013
 
2014
 
2013
 
 
(in thousands)
I&M
 
$
66,560

 
$
66,114

 
$
202,171

 
$
177,840

OPCo
 

 
37,255

 

 
107,876


The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows:
 
 
September 30, 2014
 
December 31, 2013
Company
 
As Reported on the
Balance Sheet
 
Maximum
Exposure
 
As Reported on the
Balance Sheet
 
Maximum
Exposure
 
 
(in thousands)
I&M
 
$
21,525

 
$
21,525

 
$
23,916

 
$
23,916

OPCo
 

 

 
12,810

 
12,810



248



COMBINED MANAGEMENT’S NARRATIVE DISCUSSION
AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the Registrant Subsidiaries’ management’s discussion and analysis.  The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (a) Management’s Narrative Discussion and Analysis of Results of Operations, (b) financial statements, (c) footnotes and (d) the schedules of each individual registrant.  The Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries section of the 2013 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

Customer Demand

In comparison to 2013, heating degree days for the nine months ended September 30, 2014 were up 32% in the western region and 20% in the eastern region while cooling degree days were down 7% for the same period in both the eastern and western regions. AEP's weather-normalized retail sales volumes for the third quarter of 2014 increased by 0.1% from their levels for the third quarter of 2013 and increased by 0.4% for the first nine months of 2014 from their levels for the first nine months of 2013. In comparison to 2013, AEP's industrial sales volume increased 1.2% for the three months ended September 30, 2014 and decreased 0.7% for the nine months ended September 30, 2014. The decrease in industrial sales volume is due mainly to the closure of Ormet, a large aluminum company. Excluding Ormet, AEP's nine months ended September 30, 2014 industrial sales volumes increased 3.8% over the nine months ended September 30, 2013.

ENVIRONMENTAL ISSUES

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

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

See a complete discussion of these matters in the “Environmental Issues” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2013 Annual Report.  Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If the costs of environmental compliance are not recovered, it would reduce future net income and cash flows and impact financial condition.


249



Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of September 30, 2014, the AEP System had a total generating capacity of 37,600 MWs, of which 23,700 MWs are coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the generating facilities.  For the Registrant Subsidiaries, management’s current ranges of estimates of environmental investments to comply with these requirements are listed below:
 
 
Through 2020
Estimated Environmental Investment
Company
 
Low
 
High
 
 
(in millions) 
APCo
 
$
310

 
$
360

I&M
 
370

 
430

PSO
 
270

 
310

SWEPCo
 
910

 
1,010


Several proposed regulations issued during 2014, including CO2 and Clean Water Act, are currently under review and management cannot currently predict the impact these programs may have on future resource plans or the existing generating fleet; however, the costs may be substantial. For APCo, the projected environmental investment above includes the conversion of 470 MWs of coal generation to natural gas capacity.  If natural gas conversion is not completed, the units could be closed sooner than planned.

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

Subject to the factors listed above and based upon continuing evaluation, management intends to retire the following plants or units of plants before or during 2016:
 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs) 
APCo
 
Clinch River Plant, Unit 3
 
235

APCo
 
Glen Lyn Plant
 
335

APCo
 
Kanawha River Plant
 
400

APCo/AGR
 
Sporn Plant
 
600

I&M
 
Tanners Creek Plant
 
995

PSO
 
Northeastern Station, Unit 4
 
470

SWEPCo
 
Welsh Plant, Unit 2
 
528


As of September 30, 2014, the net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the plants in the table above was $700 million.

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


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

Clean Air Act Requirements

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

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

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

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

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

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

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

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Cross-State Air Pollution Rule (CSAPR)

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

Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit. Several of the petitioners filed motions to stay the implementation of the rule pending judicial review. In 2011, the court granted the motions for stay. In 2012, the court issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the CAIR until a replacement rule is finalized. The majority determined that the CAA does not allow the Federal EPA to “overcontrol” emissions in an upwind state and that the Federal EPA exceeded its statutory authority by failing to allow states an opportunity to develop their own implementation plans before issuing a FIP. The Federal EPA and other respondents filed petitions for rehearing but in January 2013, the U.S. Court of Appeals for the District of Columbia Circuit denied all petitions for rehearing. The petition for further review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013. In April 2014, the U.S. Supreme Court issued a decision reversing in part the decision of the U.S. Court of Appeals for the District of Columbia Circuit and remanding the case for further proceedings consistent with the opinion. The parties have filed motions to govern further proceedings. The Federal EPA has filed a motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. Until the court acts on this motion, CAIR will remain in effect. Separate appeals of the Error Corrections Rule and the further revisions have been filed but no briefing schedules have been established. Management cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis. In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. The effective date of the final rule was April 16, 2012 and compliance is required within three years. Petitions for administrative reconsideration and judicial review were filed. In 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards. The Federal EPA issued revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions in March 2013. The Federal EPA is still considering additional changes to the start-up and shut down provisions. In April 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the April 2012 final rule. Industry and environmental groups have filed petitions for further review in the U.S. Supreme Court.

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. The AEP System obtained a one-year administrative extension for several units to facilitate the installation of controls or to avoid a serious reliability problem. In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades. Management remains concerned

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about the availability of compliance extensions, the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines and the lack of coordination among the Mercury and Air Toxics Standards schedule and other environmental requirements.

CO2 Regulation

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

The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from modified and reconstructed electric generating units (EGUs) and to issue guidelines for existing EGUs before June 2014, to finalize those standards by June 2015 and to require states to submit revisions to their implementation plans including such standards no later than June 2016. The President directed the Federal EPA, in developing this proposal, to directly engage states, leaders in the power sector, labor leaders and other stakeholders, to tailor the regulations to reduce costs, to develop market-based instruments and allow regulatory flexibilities and “assure that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power.” The guidelines use a “portfolio” approach to reducing emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units, expanding renewable resources and increasing customer energy efficiency. The Federal EPA issued proposed guidelines establishing state goals for CO2 emissions from existing EGUs and comments are due December 1, 2014. The Federal EPA also issued proposed regulations governing emissions of CO2 from modified and reconstructed EGUs in June 2014 and comments are due in October 2014. The standards for modified and reconstructed units include several options, including use of historic baselines or energy efficiency audits to establish source-specific CO2 emission rates or to limit CO2 emissions to no more than 1,900 pounds per MWh at larger coal units and 2,100 pounds per MWh at smaller coal units. These proposed regulations are currently under review. Management cannot currently predict the impact these programs may have on future resource plans or the existing generating fleet, but the costs may be substantial.

In 2012, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO2 emissions from new motor vehicles and its plan to phase in regulation of CO2 emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. In 2012, the U.S. Court of Appeals for the District of Columbia Circuit denied a petition for rehearing. In June 2014, the U.S. Supreme Court determined that the Federal EPA was not compelled to regulate CO2 emissions from stationary sources under the Title V or PSD programs as a result of its adoption of the motor vehicle standards, but that sources otherwise required to obtain a PSD permit may be required to perform a Best Available Control Technology analysis for CO2 emissions if they exceed a reasonable level. The Federal EPA must undertake additional rulemaking to implement the court’s decision and establish an appropriate level.

Coal Combustion Residual Rule

In 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The rule contains two alternative proposals. One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management. Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule. In 2011, the

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Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment. In 2013, the Federal EPA also issued a notice of data availability requesting comments on a narrow set of issues.

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

In February 2014, the Federal EPA completed a risk evaluation of the beneficial uses of coal fly ash in concrete and FGD gypsum in wallboard and concluded that the Federal EPA supports these beneficial uses. Currently, approximately 40% of the coal ash and other residual products from the AEP System’s generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses. Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes. In addition, surface impoundments and landfills to manage these materials are currently used at the generating facilities. The Registrant Subsidiaries will incur significant costs to upgrade or close and replace their existing facilities under the proposed solid waste management alternative. Regulation of these materials as hazardous wastes would significantly increase these costs. As the rule is not final, management is unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

Clean Water Act Regulations

In 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress. In 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments. The final rule was released by the Federal EPA in May 2014 and affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to comply with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures at facilities withdrawing more than 125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, are not expected to require any technology changes. Facilities subject to both the impingement standard and site-specific entrainment studies will typically be given at least three years to conduct and submit the results of those studies to the permit agency. Compliance timeframes will then be established by the permit agency through each facility’s National Pollutant Discharge Elimination System (NPDES) permit for installation of any required technology changes, as those permits are renewed over the next five to eight years. Petitions for review of the final rule have been filed by industry and environmental groups and have been consolidated in the U.S. Court of Appeals for the Fourth Circuit.

In addition, the Federal EPA issued an information collection request and is developing revised effluent limitation guidelines for electricity generating facilities. A proposed rule was signed in April 2013 with a final rule expected in September 2015. The Federal EPA proposed eight options of increasing stringency and cost for fly ash and bottom ash transport water, scrubber wastewater, leachate from coal combustion byproduct landfills and impoundments and other wastewaters associated with coal-fired generating units, with four labeled preferred options. Certain of the Federal EPA's preferred options have already been implemented or are part of the AEP System’s long-term plans. Management continues to review the proposal in detail to evaluate whether the plants are currently meeting the proposed limitations, what technologies have been incorporated into the long-range plans and what additional costs might be incurred if the Federal EPA's most stringent options were adopted. Management submitted detailed comments to the Federal EPA in September 2013 and participated in comments filed by various organizations of which the AEP System companies are members.

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

Climate Change

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

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

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

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

For additional information on climate change, other environmental issues and the actions management is taking to address potential impacts, see Part I of the 2013 Form 10-K under the headings entitled “Environmental and Other Matters” and “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries.”

ACCOUNTING PRONOUNCEMENTS

Pronouncements Effective in the Future

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

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

Future Accounting Changes

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

CONTROLS AND PROCEDURES

During the third quarter of 2014, management, including the principal executive officer and principal financial officer of each of AEP, APCo, I&M, OPCo, PSO and SWEPCo (collectively, the Registrants), evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of September 30, 2014, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the third quarter of 2014 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.     Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 5 incorporated herein by reference.


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Item 1A.  Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2013 includes a detailed discussion of risk factors.  The information presented below amends certain of those risk factors that have been updated and should be read in conjunction with the risk factors and information disclosed in the 2013 Annual Report on Form 10-K.

GENERAL RISKS OF OUR REGULATED OPERATIONS

Ohio may require us to refund revenue that we have collected. Affecting AEP and OPCo

Ohio law requires that the PUCO determine on an annual basis if rate adjustments included in prior orders resulted in significantly excessive earnings. If the PUCO determines there were significantly excessive earnings, the excess amount could be returned to customers. In May 2014, OPCo filed its 2013 significantly excessive earnings filing with the PUCO. In October 2014, OPCo entered into a stipulation agreement with the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2013 for OPCo. Management believes its financial statements adequately address the impact of SEET requirements. If the PUCO determines that OPCo’s earnings were significantly excessive, and requires OPCo to return a portion of its revenues to customers, it could reduce future net income and cash flows and impact financial condition.

Request for rate recovery in Louisiana may not be approved in its entirety. Affecting AEP and SWEPCo

In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC.  The filing included a $5 million annual increase, which was effective August 2014, subject to refund.  SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. These increases are subject to LPSC review. If SWEPCo cannot ultimately recover its costs that are the subject of this request, it could reduce future net income and cash flows and impact financial condition.

Request for rate and other recovery in Virginia for generation and distribution service may not be approved in its entirety. Affecting AEP and APCo

In March 2014, APCo filed a biennial generation and distribution base rate case with the Virginia SCC. APCo did not request an increase in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to the changes in the expected service life of certain plants. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to certain deferred costs. If the Virginia SCC denies all or part of the requested rate and other recovery, or if refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

Ohio may require a reduction in our 2012 and 2013 fuel deferrals. Affecting AEP and OPCo

In May 2014, the PUCO-selected outside consultant provided its final report related to their 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. In addition to this report, the PUCO will also consider the results of the pending audit of the recovery of fixed fuel costs. In May 2014, an independent auditor was selected by the PUCO and an audit of the recovery of the fixed fuel costs began in June 2014. In October 2014, the independent auditor filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are recovered through OPCo's $188.88 capacity charge, the independent auditor recommends a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. If the PUCO does not permit full recovery of OPCo’s FAC deferral, it could reduce future net income and cash flows and impact financial condition.


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Request for rate and other recovery in West Virginia may not be approved in its entirety. Affecting AEP and APCo

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

Kentucky may require a reduction in our 2013 and 2014 fuel deferrals. Affecting AEP and KPCo

In August 2014, the KPSC issued an order initiating a review of KPCo's FAC from November 2013 through April 2014. An intervenor has requested and received a procedural schedule to determine if the allocation of fuel costs has been applied appropriately. In October 2014, intervenors filed testimony that recommended the KPSC direct KPCo to modify its fuel allocation methodology and order a refund to customers of approximately $13 million, plus carrying charges at a weighted average cost of capital, related to the period January 1, 2014 through April 30, 2014. If the KPSC directs KPCo to modify its fuel allocation methodology, it could affect the allocation of costs for all periods beginning January 2014, and if any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Regulation of CO2 emissions, either through legislation or by the Federal EPA, could materially increase costs to us and our customers or cause some of our electric generating units to be uneconomical to operate or maintain. Affecting each Registrant

The U.S. Congress has not taken any significant steps toward enacting legislation to control CO2 emissions since 2009.  In December 2009, the Federal EPA issued a final endangerment finding under the CAA regarding emissions from motor vehicles.  The Federal EPA also finalized CO2 emission standards for new motor vehicles, and issued a rule that implements a permitting program for new and modified stationary sources of CO2 emissions in a phased manner.  Several groups have filed challenges to the endangerment finding and the Federal EPA’s subsequent rulemakings.  The Supreme Court agreed to review whether the Federal EPA reasonably determined that establishing standards for new motor vehicles automatically triggered regulation of stationary sources through the prevention of significant deterioration and Title V permitting programs, and determined that the Federal EPA was neither compelled nor authorized to automatically regulate stationary sources of CO2 emissions under these programs, but that the Federal EPA could establish requirements for best available control technology reviews of CO2 emissions for sources otherwise required to obtain a Prevention of Significant Deterioration permit if their emissions exceed a reasonable level.  The Federal EPA must undertake additional rulemaking to establish such requirements and a reasonable level.

In 2012, the Federal EPA issued a proposed CO2 emissions standard for new power generation sources.  In response to the comments submitted on this proposed rule, and in accordance with a directive from the President, EPA withdrew the April 2012 proposed rule and has issued a new proposal.  This proposed rule includes separate, but equivalent, standards for natural gas and coal-fired units, based on the use of partial carbon capture and storage at coal units.  In June 2014, the Federal EPA issued standards for modified and reconstructed units, and a guideline for the development of state implementation plans that would reduce carbon emissions from existing utility units. The guidelines for existing sources include aggressive emission rate goals that are composed of a number of measures.  Management believes some policy approaches being discussed would have significant and widespread negative consequences for the national economy and major U.S. industrial enterprises, including AEP and our customers.

If CO2 and other emission standards are imposed, the standards could require significant increases in capital expenditures and operating costs and could impact the dates for retirement of our coal-fired units.  We typically recover costs of complying with new requirements such as the potential CO2 and other greenhouse gases emission standards

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from customers through regulated rates in regulated jurisdictions.  For our sales of energy based on market rate authority, however, there is no such recovery mechanism.  Failure to recover these costs, should they arise, could reduce our future net income and cash flows and possibly harm our financial condition.


Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

None

Item 4.  Mine Safety Disclosures

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of DHLC, and AGR and KPCo, through their use of the Conner Run fly ash impoundment, are subject to the provisions of the Mine Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act and its related regulations require companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 contains the notices of violation and proposed assessments received by DHLC and Conner Run under the Mine Act for the quarter ended September 30, 2014.

Item 5.  Other Information

None

Item 6.  Exhibits

12 – Computation of Consolidated Ratio of Earnings to Fixed Charges

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

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

95 – Mine Safety Disclosures

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

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SIGNATURE


Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.  The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.


AMERICAN ELECTRIC POWER COMPANY, INC.



By: /s/ Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer



APPALACHIAN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY



By: /s/ Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer



Date:  October 23, 2014


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