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AMERICAN ELECTRIC POWER CO INC - Quarter Report: 2015 September (Form 10-Q)



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, 2015
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 22, 2015
 
 
American Electric Power Company, Inc.
490,817,402

 
($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, 2015
 
 
 
 
 
 
 
 
 
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 Energy
 
AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.
AEPRO
 
AEP River Operations, LLC.
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.
APSC
 
Arkansas Public Service Commission.
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.
CWIP
 
Construction Work in Progress.
DCC Fuel
 
DCC Fuel IV LLC, DCC Fuel VI LLC, DCC Fuel VII and DCC Fuel VIII 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.
IMT
 
International Marine Terminals, an equity method investment of AEPRO.
Interconnection Agreement
 
An agreement by and among APCo, I&M, KPCo and OPCo, which defined the sharing of costs and benefits associated with their respective generation plants. This agreement was terminated January 1, 2014.
IRS
 
Internal Revenue Service.
IURC
 
Indiana Utility Regulatory Commission.
KGPCo
 
Kingsport Power Company, an AEP electric utility subsidiary.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
 
Kentucky Public Service Commission.
KWh
 
Kilowatthour.
LPSC
 
Louisiana Public Service Commission.
MISO
 
Midwest Independent Transmission System Operator.
MMBtu
 
Million British Thermal Units.
MPSC
 
Michigan Public Service Commission.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWh
 
Megawatthour.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NSR
 
New Source Review.
OCC
 
Corporation Commission of the State of Oklahoma.
Ohio Phase-in-Recovery Funding
 
Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OPEB
 
Other Postretirement Benefit Plans.
OTC
 
Over the counter.
OVEC
 
Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PIRR
 
Phase-In Recovery Rider.
PJM
 
Pennsylvania – New Jersey – Maryland regional transmission organization.
PM
 
Particulate Matter.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants; APCo, I&M, OPCo, PSO and SWEPCo.

ii



Term
 
Meaning
 
 
 
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.
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.
TRA
 
Tennessee Regulatory Authority.
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 2014 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 or cost of capital to finance new capital projects and refinance existing debt.
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 competition, including competition for retail customers.
Ÿ
Weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs.
Ÿ
The cost of fuel and its transportation 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 fuel and other energy costs through regulated or competitive electric rates.
Ÿ
Our ability to build 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.
Ÿ
Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas and capacity auction returns.
Ÿ
Changes in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP.
Ÿ
The market for generation in Ohio and PJM and our ability to recover investments in our Ohio generation assets.
Ÿ
Our ability to successfully and profitably manage our competitive generation assets, including our evaluation of strategic alternatives for these assets as some of the alternatives could result in a loss.

iv



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 2014 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

Our weather-normalized retail sales volumes for the third quarter of 2015 increased by 0.9% from the third quarter of 2014. Our third quarter 2015 industrial sales increased 0.7% compared to the third quarter of 2014 primarily due to increased sales to customers in oil and gas related sectors. Weather-normalized commercial and residential sales increased 1.3% and 0.8% in the third quarter of 2015, respectively, from the third quarter of 2014.
Our weather-normalized retail sales volumes for the nine months ended September 30, 2015 increased 0.1% compared to the nine months ended September 30, 2014. Industrial sales volumes increased 0.8% compared to 2014, while weather-normalized commercial sales increased by 1.0%. Weather-normalized residential sales decreased 1.1% in comparison to the first nine months of 2014.
Merchant Fleet Alternatives

AEP is evaluating strategic alternatives for its merchant generation fleet, included in the Generation & Marketing segment, which primarily includes AGR’s generation fleet and AEGCo's Lawrenceburg Plant, both of which operate in PJM as well as a purchased power agreement related to a 54.7% interest in the Oklaunion Plant which operates in ERCOT.  Potential alternatives may include, but are not limited to, continued ownership of the merchant generation fleet, executing a purchased power agreement with a regulated affiliate for certain merchant generation units in Ohio, a spin-off of the merchant generation fleet or a sale of the merchant generation fleet.  We have not made a decision regarding the potential alternatives, nor have we set a specific time frame for a decision.  Certain of these alternatives could result in a loss which could reduce future net income and cash flow and impact financial condition.

Disposition of AEP River Operations
In October 2015, we signed an agreement to sell our commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party.  The sale of AEPRO is subject to regulatory approval including federal clearance pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976.  Upon close of the sale, the nonaffiliated party will acquire AEPRO by purchasing all of the common stock of AEP Resources, Inc., the parent company of AEPRO.  The nonaffiliated party will assume certain assets and liabilities of AEPRO, excluding the equity method investment in International Marine Terminals (IMT) which is a bulk commodity transfer facility jointly owned with Kinder Morgan L.P. "C", pension and benefit assets and liabilities and debt obligations.  We expect to net approximately $400 million in cash after taxes, debt retirement and transaction fees.  The sale is expected to close in the fourth quarter of 2015. An after tax gain ranging from approximately $100 million to $150 million is expected from the sale subject to working capital and other adjustments.

AEPRO's assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on our condensed balance sheets as of September 30, 2015 and December 31, 2014. The results of operations of AEPRO have been classified as Discontinued Operations on our condensed statements of income. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information.

Merchant Portion of Turk Plant

SWEPCo constructed the Turk Plant, a base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012 and is included in the Vertically Integrated Utilities segment. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.

1



The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This share of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under cost-based rate recovery in Texas, Louisiana, and through SWEPCo’s wholesale customers under FERC-based rates.

If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

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. In June 2015, the Supreme Court of Ohio issued a decision that reversed, as requested by OPCo, the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. In September 2015, the Supreme Court of Ohio denied the IEU's request for reconsideration and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate.
 
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 established 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 $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, which has scheduled oral arguments for the fourth quarter of 2015.

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 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. In April 2015, the PUCO issued an order that approved, with modifications, OPCo's July 2014 application to collect the unrecovered portion of the deferred capacity costs. In May 2015, the PUCO granted intervenors requests for rehearing. As of September 30, 2015, OPCo’s net deferred capacity costs balance was $392 million, including debt carrying costs. Through September 30, 2015, OPCo has collected $183 million in deferred capacity costs, and related carrying charges.

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. 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.


2



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 October 2014, the independent auditor, selected by the PUCO, 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/MW day capacity charge, the independent auditor has recommended 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 disagrees with the findings in the audit report.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.

June 2015 - May 2018 ESP Including PPA Application

In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018. The proposal also included 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 PPA.

In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the Distribution Investment Rider (DIR) with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo's and various intervenors' requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider.

In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. A hearing at the PUCO related to the PPA commenced in September 2015. In October 2015, the PUCO staff submitted testimony that opposed the PPA application as currently proposed but concluded that, with changes, a PPA could be in the public interest.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, 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 was 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.


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2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant. In February 2013, a settlement was approved by the LPSC that increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013. The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million, primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. See the “2012 Louisiana Formula Rate Filing” section of Note 4.

2015 Oklahoma Base Rate Case

In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million, which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service.

In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million, will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC.

In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million, based upon returns on common equity ranging from 8.75% to 9.3%, and increases to depreciation expense ranging from $23 million to $46 million. Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certain intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC are scheduled for December 2015. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2015 Oklahoma Base Rate Case" section of Note 4.

2015 Kingsport Base Rate Case

In September 2015, KGPCo filed a request with the TRA to increase base rates by $12 million annually based upon a proposed return on common equity of 10.66% with the new rates expected to be implemented by July 2016. See the “2015 Kingsport Base Rate Case" section of Note 4.


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New Virginia Legislation Affecting Biennial Reviews

In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA.

Kentucky Fuel Adjustment Clause Review

In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owned and operated both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court. In September 2015, the Franklin County Circuit Court issued an order that dismissed all appeals filed related to this FAC review, as agreed to by the parties to the stipulation agreement in the "2014 Kentucky Base Rate Case" discussed in Note 4.

PJM Capacity Market

AGR is required to offer all of its available generation capacity in the PJM Reliability Pricing Model (RPM) auction, which is conducted three years in advance of the delivery year.

Through May 2015, AGR provided generation capacity to OPCo for both switched and non-switched OPCo generation customers.  For switched customers, OPCo paid AGR $188.88/MW day for capacity.  For non-switched OPCo generation customers, OPCo paid 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.  As of June 2015, AGR's generation resources are compensated through the PJM capacity auction.  Shown below are the RPM results through the June 2017 through May 2018 period:
 
 
PJM
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

In June 2015, FERC approved PJM’s proposal to create a new Capacity Performance (CP) product, intended to improve generator performance and reliability during emergency events by allowing higher offers into the RPM auction and imposing greater charges for non-performance during emergency events. PJM will procure approximately 80% CP and 20% Base Capacity for the June 2018 through May 2019 and June 2019 through May 2020 periods, while transitioning to 100% CP with the June 2020 through May 2021 period. FERC also approved transition incremental auctions to procure CP for the June 2016 through May 2017 and June 2017 through May 2018 periods.


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In the third quarter of 2015, PJM conducted the two transition auctions. The transition auctions allowed generators, including AGR, to re-offer cleared capacity that qualifies as CP. Shown below are the results of the two transition auctions:
 
 
Capacity Performance Transition
PJM Auction Period
 
Incremental Auction Price
 
 
(per MW day)
June 2016 through May 2017
 
$134.00
June 2017 through May 2018
 
151.50

AGR cleared 7,169MW at $134/MW-day for the June 2016 through May 2017 period, replacing the original auction clearing price of $59.37/MW-day. AGR cleared 6,495MW for the June 2017 through May 2018 period at $151.50/MW-day, replacing the original auction clearing price of $120/MW-day.

In August 2015, PJM held its first Base Residual Auction implementing CP rules for the June 2018 through May 2019 period. PJM cleared approximately 81% of the capacity for the June 2018 through May 2019 period as CP and 19% as Base Capacity. AGR cleared 7,209 MW at $164.77/MW-day. Shown below are the results for the June 2018 through May 2019 period:
 
 
Capacity Performance
 
Base Capacity
PJM Auction Period
 
Auction Price
 
Auction Price
 
 
(per MW day)
 
(per MW day)
June 2018 through May 2019
              
$164.77
 
$150.00

The FERC order exempted Fixed Resource Requirement entities, including APCo, I&M, KPCo and WPCo, from the CP rules through the June 2018 through May 2019 period. In July 2015, AEP filed a request seeking rehearing of the FERC order approving CP, and will continue to advocate for further improvements through the PJM stakeholder process.

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 2024 for Welsh Plant, Units 1 and 3 will cost approximately $700 million, excluding AFUDC. As of September 30, 2015, SWEPCo has incurred costs of $303 million, including AFUDC, and has remaining contractual construction obligations of $62 million related to these projects.  SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. See "Mercury and Other Hazardous Air Pollutants (HAPs) Regulation" and "Climate Change, CO2 Regulation and Energy Policy" sections of “Environmental Issues” below.  As of September 30, 2015, the net book value of Welsh Plant, Units 1 and 3 was $529 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. 

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 2014 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.

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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. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing.  In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. Plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. We will continue to defend against the remaining 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, rules governing the beneficial use and disposal of coal combustion products, proposed and final 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 2014 Annual Report. We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If we are unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System. We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of September 30, 2015, the AEP System had a total generating capacity of approximately 32,100 MWs, of which approximately 18,200 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 $2.8 billion to $3.3 billion through 2020. These amounts include investments to convert some of our coal generation to natural gas.


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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.

In May 2015, we retired the following plants or units of plants:
 
 
 
 
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

Total
 
 
 
5,535


As of September 30, 2015, the net book value of the AGR units listed above was zero. The book value of the regulated plants in the table above has been approved for recovery, except for $147 million which is pending regulatory approval.

Subject to the factors listed above and based upon our continuing evaluation, we intend to retire the following units of plants during 2016:
 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs) 
PSO
 
Northeastern Station, Unit 4
 
470

SWEPCo
 
Welsh Plant, Unit 2
 
528

Total
 
 
 
998


As of September 30, 2015, the net book value of the PSO and SWEPCo units listed above before cost of removal, including related materials and supplies inventory and CWIP balances, was $177 million. 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 Northeastern Station, Unit 4 and Welsh Plant, Unit 2, we are seeking regulatory recovery of remaining net book values.

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.  We expect to begin conversion of Big Sandy Plant, Unit 1 in the fourth quarter of 2015. We expect to begin operations as a natural gas unit in the second quarter of 2016. As of September 30, 2015, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of Big Sandy Plant, Unit 1 was $110 million.

We are also in the process of obtaining permits following the Virginia SCC and WVPSC's approval for the conversion of APCo's 470 MW Clinch River Plant, Units 1 and 2 to natural gas. In September 2015, we retired the coal-related assets of Clinch River Plant, Units 1 and 2. Of the coal-related assets retired in September 2015, $14 million is pending regulatory approval. We expect to begin operations as a natural gas unit in the first quarter of 2016 for Clinch River

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Plant, Unit 1 and the second quarter of 2016 for Clinch River Plant, Unit 2. As of September 30, 2015, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of Clinch River Plant, Units 1 and 2 was $148 million.

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.  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 and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit.  The U.S. Court of Appeals for the District of Columbia Circuit ordered CSAPR to take effect on January 1, 2015 while the remand proceeding was still pending. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit remanded the rule to the Federal EPA. All of the states in which our power plants are located are covered by CSAPR. 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) will 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 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.  In March 2012, the Federal EPA disapproved certain portions of the Arkansas regional haze SIP. In April 2015, the Federal EPA published a proposed FIP to replace the disapproved portions, including revised BART determinations for the Flint Creek Plant that are consistent with the environmental controls currently under construction. 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 July 2015, we submitted comments to the proposed Arkansas FIP and participate in comments filed by industry associations of which we are members. We support compliance with CSAPR programs as satisfaction of the BART requirements.

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.  This rule was overturned by the U.S. Supreme Court. The Federal EPA proposed to include CO2 emissions in standards that apply to new and existing electric utility units. See "Climate Change, CO2 Regulation and Energy Policy" section below.

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The Federal EPA also issued new, more stringent national ambient air quality standards (NAAQS) for PM, SO2 and ozone. In October 2015, the Federal EPA announced a lower final NAAQS for ozone of 70 parts per billion. States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for our facilities as a result of those evaluations. We cannot currently predict the nature, stringency or timing of those requirements.

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

Cross-State Air Pollution Rule (CSAPR)

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

Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit.  In 2012, the court issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing 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 petition for 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 Federal EPA 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. The court granted the Federal EPA's motion. The parties filed briefs and presented oral arguments. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit found that the Federal EPA over-controlled the SO2 and/or NOx budgets of 14 states. The U.S. Court of Appeals for the District of Columbia Circuit remanded the rule to the Federal EPA to timely revise the rule consistent with the court’s opinion while CSAPR remains in place. The Federal EPA is reviewing the decision and will take further action once their review is complete. Separate appeals of the Error Corrections Rule and the further revisions were filed but no briefing schedules have been established.

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 units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of nonmercury metals) and hydrogen chloride (as a surrogate for acid gases).  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 was required within three years. The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and the revised rule provides alternative work practice standards for operators during start-up and shut down periods.  We have obtained a one-year administrative extension at several units to facilitate the installation of controls or to avoid a serious reliability problem. In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades. We remain concerned about the availability of compliance extensions, the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines and the lack of coordination among the Mercury and Air Toxics Standards (MATS) schedule and other environmental requirements.

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Petitions for administrative reconsideration and judicial review of the final rule 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. A final rule on reconsideration was issued in 2014 and a proposed rule containing technical corrections was issued in early 2015. 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 trade groups and several states filed petitions for further review in the U.S. Supreme Court and the court granted those petitions in November 2014.

In June 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit and remanded the MATS rule for further proceedings consistent with its decision that the Federal EPA was unreasonable in refusing to consider costs in its determination whether to regulate emissions of HAPs from power plants. The case has been remanded to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings consistent with the U.S. Supreme Court’s decision. We will continue to evaluate the impact of this decision and until further action by the U.S. Court of Appeals for the District of Columbia Circuit, the rule remains in place.

Climate Change, CO2 Regulation and Energy Policy

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 that can assist in reducing carbon emissions.  We are taking steps to comply with these requirements, including increasing our wind power purchases and broadening our portfolio of energy efficiency programs.

In the absence of comprehensive federal climate change or energy policy legislation, 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 under the CAA.  The new proposal was issued in September 2013 and requires new large natural gas units to meet a limit of 1,000 pounds of CO2 per MWh of electricity generated and small natural gas units to meet a limit of 1,100 pounds of CO2 per MWh.  New coal-fired units are required to meet a limit of 1,100 pounds of CO2 per MWh, with the option to meet a 1,000 pound per MWh limit if they choose to average emissions over multiple years.  

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 plans implementing the guidelines no later than June 2016.

In August 2015, the Federal EPA announced the final standards for new, modified and reconstructed fossil fired steam generating units and combustion turbines, guidelines for the development of state plans to regulate CO2 emissions from existing sources and proposed two options for a federal plan. The rules will become effective 60 days following publication. The final standard for new combustion turbines is 1,000 pounds of CO2 per MWh and the final standard for new fossil steam units is 1,400 pounds of CO2 per MWh. Reconstructed turbines are subject to the same standard as new units and no standard for modified combustion turbines was issued. Reconstructed fossil steam units are subject to a standard of 1,800 pounds of CO2 per MWh for larger units and 2,000 pounds of CO2 per MWh for smaller units. Modified fossil steam units will be subject to a site specific standard no lower than the standards that would be applied if the units were reconstructed.

The final emissions guidelines for existing sources are based on a series of declining performance standards that are implemented beginning in 2022 through 2029. Affected units must achieve a standard of 771 pounds of CO2 per MWh for existing natural gas combined cycle units and 1,305 pounds of CO2 per MWh for existing fossil steam units by 2030. The Federal EPA also developed a set of rate-based and mass-based state goals and has proposed “model” rules that can be adopted by the states that would allow sources within “trading ready” state programs to trade, bank or sell

11



allowances or credits issued by the states or Federal EPA. The Federal EPA intends to finalize either a rate-based or mass-based trading program that can be enforced in states that fail to submit approved plans by the deadlines established in the final guidelines. States are required to submit final plans or an extension request by September 2016 to the Federal EPA. States receiving an extension request must submit final plans by September 2018. We are reviewing the pre-publication version of the final rule and evaluating the rule’s impacts as well as the anticipated actions by states where our assets are located. The final rule was already challenged in the courts and we expect additional lawsuits once the rule is published in the Federal Register.

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 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 (BACT) analysis for CO2 emissions if they exceed a reasonable level. The Federal EPA removed those provisions of the final rule from the Code of Federal Regulations that were inconsistent with the U.S. Supreme Court’s decision but continues to apply a 75,000 ton per year threshold to trigger the need for a BACT analysis. Petitions were filed with the U.S. Court of Appeals for the District of Columbia Circuit seeking to amend the judgment in the case to require Federal EPA to establish a reasonable minimum level. Those petitions were denied.

Federal and state legislation or regulations that mandate limits on the emission of CO2 could 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.

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 (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants.  The proposed rule contained two alternative proposals.  One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management.  Both proposals would impose stringent requirements for the construction of new coal ash landfills and existing unlined surface impoundments.

In the final rule, the Federal EPA elected to regulate CCR as a non-hazardous solid waste and issued new minimum federal solid waste management standards. On the effective date, the rule applies to new and existing active CCR landfills and CCR surface impoundments at operating electric utility or independent power production facilities. The rule imposes new and additional construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements. The rule does not apply to inactive CCR landfills and inactive surface impoundments at retired generating stations or the beneficial use of CCR. The rule is self-implementing so state action is not required. Because of this self-implementing feature, the rule contains extensive record keeping, notice and internet posting requirements. Because we currently use surface impoundments and landfills to manage CCR materials at our generating facilities, we will incur significant costs to upgrade or close and replace these existing facilities at some point in the future as the new rule is implemented.

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.  Encapsulated beneficial uses are not materially impacted by the new rule but additional demonstrations may be required to continue land applications in significant amounts except in road construction projects.

12



The final rule was published in the Federal Register in April 2015 and becomes effective six months after publication. The final rule provides for a staggered compliance schedule for the implementation of the rule’s many requirements. We recorded a $95 million increase in asset retirement obligations in the second quarter of 2015 primarily due to the publication of the final rule. Given the schedule for implementation, we will continue to evaluate the rule's impact on operations.

Clean Water Act (CWA) Regulations

In 2014, the Federal EPA issued a final rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The final rule 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 were filed by industry and environmental groups and are currently pending in the U.S. Court of Appeals for the Second Circuit.

In addition, the Federal EPA developed revised effluent limitation guidelines for electricity generating facilities.  A pre-publication copy of the final rule was announced and made available in September 2015. In addition to other requirements, in the final rule the Federal EPA establishes limits on flue gas desulfurization wastewater, zero discharge for fly ash and bottom ash transport water and flue gas mercury control wastewater. Compliance with the final rule is as soon as possible after November 2018 and no later than December 2023. These new requirements will be implemented through each facility’s wastewater discharge permit. We continue to review the final rule 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.

In June 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This jurisdictional definition applies 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. The final definition continues to recognize traditional navigable waters of the U.S. as jurisdictional as well as certain exclusions. The rule also contains a number of new specific definitions and criteria for determining whether certain other waters are jurisdictional because of a “significant nexus." We believe that clarity and efficiency in the permitting process is needed. We remain concerned that the rule introduces new concepts and could subject more of our operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. The final rule is being challenged in both courts of appeal and district courts. Challengers include industry associations of which we are members. The U.S. Court of Appeal for the Sixth Circuit has granted a nationwide stay of the rule pending jurisdictional determinations.

13



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.

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 and capacity to serve SSO customers and provides transmission and distribution services 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.
In October 2015, we signed an agreement to sell AEPRO to a nonaffiliated party. The AEP River Operations segment is comprised entirely of AEPRO. However, we will retain AEPRO's investment in IMT. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information.


14



The table below presents Earnings Attributable to AEP Common Shareholders by segment for the three and nine months ended September 30, 2015 and 2014.
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Vertically Integrated Utilities
$
274

 
$
219

 
$
780

 
$
651

Transmission and Distribution Utilities
113

 
92

 
288

 
279

AEP Transmission Holdco
46

 
43

 
147

 
114

Generation & Marketing
91

 
117

 
360

 
378

AEP River Operations
4

 
11

 
16

 
17

Corporate and Other (a)
(9
)
 
11

 
(13
)
 
4

Earnings Attributable to AEP Common Shareholders
$
519

 
$
493

 
$
1,578

 
$
1,443

(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.

AEP CONSOLIDATED

Third Quarter of 2015 Compared to Third Quarter of 2014

Earnings Attributable to AEP Common Shareholders increased from $493 million in 2014 to $519 million in 2015 primarily due to:

Successful rate proceedings in various jurisdictions.
An increase in revenues due to annual formula rate adjustments.
An increase in weather-related usage.
A decrease in expenses due to a settlement and revision of certain asset retirement obligations.
An increase in transmission investment which resulted in higher revenues and income.

These increases were partially offset by:

A decrease in generation revenues due to lower capacity revenue.
A decrease in off-system sales margins due to lower market prices and reduced sales volumes.
An increase in employee-related expenses.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

Earnings Attributable to AEP Common Shareholders increased from $1.4 billion in 2014 to $1.6 billion in 2015 primarily due to:

Successful rate proceedings in various jurisdictions.
An increase in revenues due to annual formula rate adjustments.
An increase in weather-related usage.
A decrease in expenses due to a settlement and revision of certain asset retirement obligations.
An increase in transmission investment which resulted in higher revenues and income.
Favorable retail, trading and marketing activity.

These increases were partially offset by:

A decrease in generation revenues due to lower capacity revenue.
A decrease in off-system sales margins due to lower market prices and reduced sales volumes.
A decrease in weather normalized sales.

Our results of operations by operating segment are discussed below.

15



VERTICALLY INTEGRATED UTILITIES
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 Vertically Integrated Utilities
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Revenues
 
$
2,471

 
$
2,450

 
$
7,159

 
$
7,288

Fuel and Purchased Electricity
 
931

 
1,010

 
2,695

 
3,038

Gross Margin
 
1,540

 
1,440

 
4,464

 
4,250

Other Operation and Maintenance
 
653

 
615

 
1,844

 
1,809

Depreciation and Amortization
 
264

 
257

 
802

 
772

Taxes Other Than Income Taxes
 
97

 
95

 
288

 
278

Operating Income
 
526

 
473

 
1,530

 
1,391

Interest and Investment Income
 
1

 
2

 
4

 
3

Carrying Costs Income
 
4

 
1

 
9

 
2

Allowance for Equity Funds Used During Construction
 
16

 
12

 
46

 
33

Interest Expense
 
(130
)
 
(133
)
 
(392
)
 
(396
)
Income Before Income Tax Expense and Equity Earnings
 
417

 
355

 
1,197

 
1,033

Income Tax Expense
 
142

 
135

 
416

 
380

Equity Earnings of Unconsolidated Subsidiaries
 

 

 
2

 
1

Net Income
 
275

 
220

 
783

 
654

Net Income Attributable to Noncontrolling Interests
 
1

 
1

 
3

 
3

Earnings Attributable to AEP Common Shareholders
 
$
274

 
$
219

 
$
780

 
$
651


Summary of KWh Energy Sales for Vertically Integrated Utilities
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions of KWhs)
Retail:
 

 
 

 
 

 
 

Residential
9,019

 
8,505

 
26,070

 
26,126

Commercial
7,008

 
6,743

 
19,315

 
18,980

Industrial
8,882

 
8,962

 
26,178

 
26,319

Miscellaneous
616

 
608

 
1,739

 
1,740

Total Retail
25,525

 
24,818

 
73,302

 
73,165

 
 
 
 
 
 
 
 
Wholesale (a)
6,577

 
8,632

 
20,748

 
27,418

(a)
Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers.


16



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 revenues 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,
 
2015
 
2014
 
2015
 
2014
 
(in degree days)
Eastern Region
 

 
 

 
 

 
 

Actual  Heating (a)

 
2

 
2,138

 
2,248

Normal  Heating (b)
5

 
5

 
1,748

 
1,736

 
 
 
 
 
 
 
 
Actual  Cooling (c)
702

 
559

 
1,104

 
921

Normal  Cooling (b)
728

 
733

 
1,057

 
1,062

 
 
 
 
 
 
 
 
Western Region
 

 
 

 
 

 
 

Actual  Heating (a)

 

 
1,049

 
1,233

Normal  Heating (b)
1

 
1

 
912

 
921

 
 
 
 
 
 
 
 
Actual  Cooling (c)
1,472

 
1,246

 
2,190

 
1,926

Normal  Cooling (b)
1,398

 
1,399

 
2,114

 
2,109


(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.


17



Third Quarter of 2015 Compared to Third Quarter of 2014
Reconciliation of Third Quarter of 2014 to Third Quarter of 2015
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
 
 
 
Third Quarter of 2014
 
$
219

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
128

Off-system Sales
 
(24
)
Transmission Revenues
 
(10
)
Other Revenues
 
6

Total Change in Gross Margin
 
100

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(38
)
Depreciation and Amortization
 
(7
)
Taxes Other Than Income Taxes
 
(2
)
Interest and Investment Income
 
(1
)
Carrying Costs Income
 
3

Allowance for Equity Funds Used During Construction
 
4

Interest Expense
 
3

Total Change in Expenses and Other
 
(38
)
 
 
 

Income Tax Expense
 
(7
)
 
 
 
Third Quarter of 2015
 
$
274


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 $128 million primarily due to the following:
The effect of successful rate proceedings in our service territories which include:
A $40 million increase primarily due to increases in rates in West Virginia, offset by decreases in rates in Virginia and formula rates in both jurisdictions.
A $25 million increase for SWEPCo primarily due to revenue increases from rate riders in Louisiana and Texas.
A $20 million increase for I&M primarily due to rate increases from Indiana rate riders and annual formula rate adjustments.
An $11 million increase for PSO primarily due to revenue increases from rate riders.
For the increases described above, $30 million relate to riders/trackers which have corresponding increases in expense items below.
A $51 million increase in weather-related usage.
These increases were partially offset by:
A $19 million decrease primarily due to lower weather-normalized retail sales in our western region.
Margins from Off-system Sales decreased $24 million primarily due to lower market prices and decreased sales volumes.
Transmission Revenues decreased $10 million primarily due to decreased PJM revenues, partially offset by an increase in SPP margins.
Other Revenues increased $6 million primarily due to a 2014 MPSC order disallowing $4 million of 2012 to 2014 lost revenue related to Demand Side Management (DSM).


18



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

Other Operation and Maintenance expenses increased $38 million primarily due to the following:
A $20 million increase in employee-related expenses.
A $17 million increase in recoverable expenses, primarily PJM expenses currently fully recovered in rate recovery riders/trackers, partially offset by lower River Transportation Division (RTD) barging costs.
A $5 million increase in SPP transmission services.
A $4 million increase in storm expenses.
These increases were partially offset by:
An $8 million decrease due to a 2014 accrual for expected environmental remediation costs at I&M.
Depreciation and Amortization expenses increased $7 million primarily due to amortization related to an advanced metering rider implemented in November 2014 in Oklahoma as well as an overall higher depreciable base.
Allowance for Equity Funds Used During Construction increased $4 million primarily due to increases in environmental construction and transmission projects.
Income Tax Expense increased $7 million primarily due to an increase in pretax book income, partially offset by the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis.

19



Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
 
 
 
Nine Months Ended September 30, 2014
 
$
651

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
340

Off-system Sales
 
(118
)
Transmission Revenues
 
(9
)
Other Revenues
 
1

Total Change in Gross Margin
 
214

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(35
)
Depreciation and Amortization
 
(30
)
Taxes Other Than Income Taxes
 
(10
)
Interest and Investment Income
 
1

Carrying Costs Income
 
7

Allowance for Equity Funds Used During Construction
 
13

Interest Expense
 
4

Total Change in Expenses and Other
 
(50
)
 
 
 

Income Tax Expense
 
(36
)
Equity Earnings
 
1

 
 
 
Nine Months Ended September 30, 2015
 
$
780


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 $340 million primarily due to the following:
The effect of successful rate proceedings in our service territories which include:
A $108 million increase primarily due to increases in rates in West Virginia and Virginia, as well as an adjustment due to the amended Virginia law impacting biennial reviews.
A $74 million increase for I&M primarily due to rate increases from Indiana rate riders and annual formula rate adjustments.
A $68 million increase for SWEPCo primarily due to increases in municipal and cooperative revenues due to annual formula rate adjustments and revenue increases from SWEPCo rate riders in Louisiana and Texas.
A $27 million increase for PSO primarily due to revenue increases from rate riders.
For the increases described above, $77 million relate to riders/trackers which have corresponding increases in expense items below.
A $52 million increase in weather-related usage.
These increases were partially offset by:
A $25 million decrease in weather-normalized load primarily due to lower residential sales in the eastern region.
Margins from Off-system Sales decreased $118 million primarily due to lower market prices and decreased sales volumes.
Transmission Revenues decreased $9 million primarily due to decreased PJM revenues, partially offset by an increase in SPP margins.

20



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

Other Operation and Maintenance expenses increased $35 million primarily due to the following:
A $54 million increase in recoverable expenses, primarily PJM expenses and vegetation management expenses currently fully recovered in rate recovery riders/trackers, partially offset by lower RTD barging costs.
A $13 million increase in SPP and PJM transmission services.
These increases were partially offset by:
An $18 million decrease in vegetation management expenses and storm expenses.
A $14 million decrease due to a 2014 accrual for expected environmental remediation costs and a 2015 reduction of an environmental liability at I&M.
Depreciation and Amortization expenses increased $30 million primarily due to amortization related to an advanced metering rider implemented in November 2014 in Oklahoma as well as an overall higher depreciable base.
Taxes Other Than Income Taxes increased $10 million primarily due to an increase in property taxes.
Carrying Costs Income increased $7 million primarily due to increased riders and trackers in our jurisdictions, including the Indiana and Michigan Life Cycle Management Riders, the Kentucky Environmental Surcharge Rider, the Indiana Dry Sorbent Injection Rider, as well as an increase in carrying charges related to West Virginia ENEC deferrals.
Allowance for Equity Funds Used During Construction increased $13 million primarily due to increases in environmental construction and transmission projects.
Income Tax Expense increased $36 million primarily due to an increase in pretax book income, partially offset by the regulatory accounting treatment of state income taxes.


21



TRANSMISSION AND DISTRIBUTION UTILITIES
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Transmission and Distribution Utilities
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Revenues
 
$
1,189

 
$
1,231

 
$
3,520

 
$
3,580

Fuel and Purchased Electricity
 
229

 
377

 
920

 
1,123

Amortization of Generation Deferrals
 
55

 
27

 
122

 
83

Gross Margin
 
905

 
827

 
2,478

 
2,374

Other Operation and Maintenance
 
348

 
329

 
956

 
920

Depreciation and Amortization
 
198

 
182

 
536

 
499

Taxes Other Than Income Taxes
 
122

 
117

 
362

 
344

Operating Income
 
237

 
199

 
624

 
611

Interest and Investment Income
 
2

 
3

 
5

 
9

Carrying Costs Income (Expense)
 
(2
)
 
6

 
10

 
20

Allowance for Equity Funds Used During Construction
 
3

 
3

 
11

 
8

Interest Expense
 
(68
)
 
(68
)
 
(206
)
 
(210
)
Income Before Income Tax Expense
 
172

 
143

 
444

 
438

Income Tax Expense
 
59

 
51

 
156

 
159

Net Income
 
113

 
92

 
288

 
279

Net Income Attributable to Noncontrolling Interests
 

 

 

 

Earnings Attributable to AEP Common Shareholders
 
$
113

 
$
92

 
$
288

 
$
279


Summary of KWh Energy Sales for Transmission and Distribution Utilities
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions of KWhs)
Retail:
 

 
 

 
 

 
 

Residential
7,590

 
7,194

 
20,486

 
20,280

Commercial
7,033

 
6,796

 
19,320

 
19,012

Industrial
5,665

 
5,489

 
16,754

 
16,262

Miscellaneous
194

 
187

 
532

 
540

Total Retail (a)
20,482

 
19,666

 
57,092

 
56,094

 
 
 
 
 
 
 
 
Wholesale (b)
497

 
575

 
1,460

 
1,727


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


22



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 revenues 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,
 
2015
 
2014
 
2015
 
2014
 
(in degree days)
Eastern Region
 

 
 

 
 

 
 

Actual  Heating (a)

 
1

 
2,575

 
2,540

Normal  Heating (b)
6

 
7

 
2,073

 
2,074

 
 
 
 
 
 
 
 
Actual  Cooling (c)
620

 
581

 
970

 
943

Normal  Cooling (b)
666

 
663

 
956

 
946

 
 
 
 
 
 
 
 
Western Region
 

 
 

 
 

 
 

Actual  Heating (a)

 

 
320

 
302

Normal  Heating (b)

 

 
192

 
200

 
 
 
 
 
 
 
 
Actual  Cooling (d)
1,476

 
1,367

 
2,380

 
2,309

Normal  Cooling (b)
1,355

 
1,346

 
2,381

 
2,358


(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.


23



Third Quarter of 2015 Compared to Third Quarter of 2014
Reconciliation of Third Quarter of 2014 to Third Quarter of 2015
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
 
 
 
Third Quarter of 2014
 
$
92

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
117

Off-system Sales
 
(9
)
Transmission Revenues
 
(33
)
Other Revenues
 
3

Total Change in Gross Margin
 
78

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(19
)
Depreciation and Amortization
 
(16
)
Taxes Other Than Income Taxes
 
(5
)
Interest and Investment Income
 
(1
)
Carrying Costs Income
 
(8
)
Total Change in Expenses and Other
 
(49
)
 
 
 

Income Tax Expense
 
(8
)
 
 
 

Third Quarter of 2015
 
$
113


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 $117 million primarily due to the following:
A $65 million increase in Ohio transmission and PJM revenues primarily due to the energy supplied as result of the Ohio auction and a regulatory change which resulted in revenues collected through a non-bypassable transmission rider, partially offset by a corresponding decrease in Transmission Revenues below.
A $33 million Ohio regulatory provision recorded in 2014.
A $7 million increase in revenues associated with the Ohio Distribution Investment Rider (DIR).
A $7 million increase in revenues associated with the gridSMART®, Enhanced Service Reliability and Retail Stability Riders. These riders have corresponding increases in other expense items below.
A $6 million increase in TCC and TNC revenues primarily due to the recovery of ERCOT transmission expenses, offset in Other Operation and Maintenance expenses below.
A $4 million increase in commercial sales in Ohio.
A $4 million increase in weather-related usage in Texas.
These increases were partially offset by:
A $14 million decrease in base rates due to the discontinuance of seasonal rates in Ohio.
A $14 million decrease in revenues associated with the recovery of 2012 storm costs under the Ohio Storm Damage Recovery Rider which ended in April 2015. This decrease in Retail Margins is primarily offset by a decrease in Other Operation and Maintenance expenses below.
Margins from Off-system Sales decreased $9 million primarily due to losses from a legacy OPCo power contract.
Transmission Revenues decreased $33 million primarily due to:
A $37 million decrease in Network Integrated Transmission Service (NITS) revenue due to OPCo assuming the responsibility for items determined to be cost-based transmission-related charges that were the responsibility of the CRES providers prior to June 2015, partially offset by a corresponding increase in Retail Margins above.
This decrease was partially offset by:
A $5 million increase primarily due to increased transmission investment in ERCOT.

24



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

Other Operation and Maintenance expenses increased $19 million primarily due to the following:
A $24 million increase primarily due to PJM and ERCOT expenses fully recovered in rate recovery riders/trackers.
A $7 million increase in employee-related expenses.
These increases were partially offset by:
A $14 million decrease due to the completion of the amortization of 2012 deferred Ohio storm expenses in April 2015. This decrease was offset by a corresponding decrease in Retail Margins above.
Depreciation and Amortization expenses increased $16 million primarily due to the following:
A $7 million increase due to an increase in the depreciable base of transmission and distribution assets.
A $4 million increase in amortization of TCC's securitization transition asset, partially offset in Other Revenues above.
A $3 million increase in Ohio gridSMART® capital carrying charges primarily due to a rider rate increase effective June 2015. This increase was offset by a corresponding increase in Retail Margins above.
Taxes Other Than Income Taxes increased $5 million primarily due to an increase in property taxes.
Carrying Costs Income decreased $8 million primarily due to the collection of carrying costs on deferred capacity charges beginning June 2015.
Income Tax Expense increased $8 million primarily due to an increase in pretax book income.

25



Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
 
 
 
Nine Months Ended September 30, 2014
 
$
279

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
161

Off-system Sales
 
(13
)
Transmission Revenues
 
(54
)
Other Revenues
 
10

Total Change in Gross Margin
 
104

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(36
)
Depreciation and Amortization
 
(37
)
Taxes Other Than Income Taxes
 
(18
)
Interest and Investment Income
 
(4
)
Carrying Costs Income
 
(10
)
Allowance for Equity Funds Used During Construction
 
3

Interest Expense
 
4

Total Change in Expenses and Other
 
(98
)
 
 
 

Income Tax Expense
 
3

 
 
 

Nine Months Ended September 30, 2015
 
$
288


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 $161 million primarily due to the following:
A $91 million increase in Ohio transmission and PJM revenues primarily due to the energy supplied as result of the Ohio auction and a regulatory change which resulted in revenues collected through a non-bypassable transmission rider, partially offset by a corresponding decrease in Transmission Revenues below.
A $33 million Ohio regulatory provision recorded in 2014.
A $24 million increase in TCC and TNC revenues primarily due to the recovery of ERCOT transmission expenses, offset in Other Operation and Maintenance expenses below.
A $22 million increase in revenues associated with the Ohio DIR.
A $5 million increase in weather-related usage in Texas.
These increases were partially offset by:
A $19 million decrease in the Energy Efficiency (EE), Peak Demand Reduction Cost Recovery Rider (PDR) revenues in Ohio and associated deferrals. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
An $11 million decrease in revenues associated with the recovery of 2012 storm costs under the Ohio Storm Damage Recovery Rider which ended in April 2015. This decrease in Retail Margins is primarily offset by a decrease in Other Operation and Maintenance expenses below.
Margins from Off-system Sales decreased $13 million primarily due to losses from a legacy OPCo power contract.
Transmission Revenues decreased $54 million primarily due to the following:
A $44 million decrease in NITS revenue primarily due to OPCo assuming the responsibility for items determined to be cost-based transmission-related charges that were the responsibility of the CRES providers prior to June 2015, partially offset by a corresponding increase in Retail Margins above.

26



A $12 million decrease in Ohio revenues related to a lower annual transmission formula rate true-up.
A $9 million OPCo transmission regulatory settlement in 2015.
These decreases were partially offset by:
An $18 million increase primarily due to increased transmission investment in ERCOT.
Other Revenues increased $10 million primarily due to $5 million of increased pole attachment revenue for OPCo and a $3 million increase in Texas securitization revenues, offset in Depreciation and Amortization below.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $36 million primarily due to the following:
A $36 million increase primarily due to PJM and ERCOT expenses fully recovered in rate recovery riders/trackers.
A $13 million increase in distribution expenses including system improvements and vegetation management expenses.
An $8 million increase in PJM and SPP transmission services.
A $6 million increase due to PUCO ordered contributions to the Ohio Growth Fund.
These increases were partially offset by:
A $19 million decrease in EE and PDR costs and associated deferrals. This decrease was offset by a corresponding decrease in Retail Margins above.
A $6 million decrease in remitted Universal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset by a corresponding decrease in Retail Margins above.
Depreciation and Amortization expenses increased $37 million primarily due to the following:
A $19 million increase due to an increase in the depreciable base of transmission and distribution assets.
An $11 million increase in amortization of TCC's securitization transition asset, partially offset in Other Revenues.
Taxes Other Than Income Taxes increased $18 million primarily due to increased property taxes.
Carrying Costs Income decreased $10 million primarily due to the collection of carrying costs on deferred capacity charges beginning June 2015.

27



AEP TRANSMISSION HOLDCO
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
AEP Transmission Holdco
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Transmission Revenues
 
$
88

 
$
55

 
$
245

 
$
140

Other Operation and Maintenance
 
11

 
7

 
27

 
18

Depreciation and Amortization
 
12

 
6

 
30

 
17

Taxes Other Than Income Taxes
 
17

 
10

 
50

 
23

Operating Income
 
48

 
32

 
138

 
82

Allowance for Equity Funds Used During Construction
 
14

 
12

 
40

 
33

Interest Expense
 
(10
)
 
(6
)
 
(27
)
 
(16
)
Income Before Income Tax Expense and Equity Earnings
 
52

 
38

 
151

 
99

Income Tax Expense
 
23

 
17

 
66

 
47

Equity Earnings of Unconsolidated Subsidiaries
 
17

 
22

 
63

 
62

Net Income
 
46

 
43

 
148

 
114

Net Income Attributable to Noncontrolling Interests
 

 

 
1

 

Earnings Attributable to AEP Common Shareholders
 
$
46

 
$
43

 
$
147

 
$
114


Summary of Net Plant in Service and CWIP for AEP Transmission Holdco
 
 
As of September 30,
 
 
2015
 
2014
 
 
(in millions)
Net Plant in Service
 
$
2,253

 
$
1,308

CWIP
 
1,298

 
1,050


28



Third Quarter of 2015 Compared to Third Quarter of 2014
 
Reconciliation of Third Quarter of 2014 to Third Quarter of 2015
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Third Quarter of 2014
 
$
43

 
 
 
Changes in Transmission Revenues:
 
 
Transmission Revenues
 
33

Total Change in Transmission Revenues
 
33

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(4
)
Depreciation and Amortization
 
(6
)
Taxes Other Than Income Taxes
 
(7
)
Allowance for Equity Funds Used During Construction
 
2

Interest Expense
 
(4
)
Total Change in Expenses and Other
 
(19
)
 
 
 
Income Tax Expense
 
(6
)
Equity Earnings
 
(5
)
 
 
 
Third Quarter of 2015
 
$
46


The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and non-affiliates, were as follows:

Transmission Revenues increased $33 million primarily due to an increase in projects placed in-service by our wholly-owned transmission subsidiaries.

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

Other Operation and Maintenance expenses increased $4 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $6 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $7 million primarily due to increased property taxes.
Interest Expense increased $4 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $6 million primarily due to an increase in pretax book income and by the recording of federal and state income tax adjustments in the third quarter of 2015 compared to the third quarter of 2014.
Equity Earnings decreased $5 million primarily due to increased expense related to cross-arms on ETT transmission lines.

29



Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
 
Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Nine Months Ended September 30, 2014
 
$
114

 
 
 
Changes in Transmission Revenues:
 
 
Transmission Revenues
 
105

Total Change in Transmission Revenues
 
105

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(9
)
Depreciation and Amortization
 
(13
)
Taxes Other Than Income Taxes
 
(27
)
Allowance for Equity Funds Used During Construction
 
7

Interest Expense
 
(11
)
Total Change in Expenses and Other
 
(53
)
 
 
 
Income Tax Expense
 
(19
)
Equity Earnings
 
1

Net Income Attributable to Noncontrolling Interests
 
(1
)
 
 
 
Nine Months Ended September 30, 2015
 
$
147


The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and non-affiliates, were as follows:

Transmission Revenues increased $105 million primarily due to an increase in projects placed in-service by our wholly-owned transmission subsidiaries.

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

Other Operation and Maintenance expenses increased $9 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $13 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $27 million primarily due to increased property taxes.
Allowance for Equity Funds Used During Construction increased $7 million primarily due to increased transmission investment.
Interest Expense increased $11 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $19 million primarily due to an increase in pretax book income.


30



GENERATION & MARKETING
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
Generation & Marketing
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Revenues
 
$
835

 
$
901

 
$
2,806

 
$
3,065

Fuel, Purchased Electricity and Other
 
564

 
529

 
1,771

 
1,894

Gross Margin
 
271

 
372

 
1,035

 
1,171

Other Operation and Maintenance
 
61

 
122

 
277

 
363

Depreciation and Amortization
 
51

 
56

 
152

 
169

Taxes Other Than Income Taxes
 
10

 
12

 
30

 
37

Operating Income
 
149

 
182

 
576

 
602

Interest and Investment Income
 

 
2

 
2

 
4

Interest Expense
 
(10
)
 
(12
)
 
(31
)
 
(35
)
Income Before Income Tax Expense
 
139

 
172

 
547

 
571

Income Tax Expense
 
48

 
55

 
187

 
193

Net Income
 
91

 
117

 
360

 
378

Net Income Attributable to Noncontrolling Interests
 

 

 

 

Earnings Attributable to AEP Common Shareholders
 
$
91

 
$
117

 
$
360

 
$
378


Summary of MWhs Generated for Generation & Marketing
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions of MWhs)
Fuel Type:
 

 
 

 
 

 
 

Coal
7

 
16

 
23

 
37

Natural Gas
3

 
2

 
10

 
6

Wind
1

 

 
1

 

Total MWhs
11

 
18

 
34

 
43



31



Third Quarter of 2015 Compared to Third Quarter of 2014
Reconciliation of Third Quarter of 2014 to Third Quarter of 2015
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
 
 
 
Third Quarter of 2014
 
$
117

 
 
 

Changes in Gross Margin:
 
 

Generation
 
(96
)
Retail, Trading and Marketing
 
(6
)
Other
 
1

Total Change in Gross Margin
 
(101
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
61

Depreciation and Amortization
 
5

Taxes Other Than Income Taxes
 
2

Interest and Investment Income
 
(2
)
Interest Expense
 
2

Total Change in Expenses and Other
 
68

 
 
 

Income Tax Expense
 
7

 
 
 

Third Quarter of 2015
 
$
91


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 certain cost of service for retail operations were as follows:

Generation decreased $96 million primarily due to lower capacity revenue due to the termination of the Power Supply Agreement between AGR and OPCo on May 31, 2015.
Retail, Trading and Marketing decreased $6 million primarily due to decreased wholesale trading and marketing performance.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses decreased $61 million primarily due to a settlement and revision of certain asset retirement obligations and decreased plant outage and maintenance costs.
Depreciation and Amortization expenses decreased $5 million primarily due to reduced plant in-service.
Income Tax Expense decreased $7 million primarily due to a decrease in pretax book income, partially offset by the recording of federal and state income tax adjustments.


32



Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
 
 
 
Nine Months Ended September 30, 2014
 
$
378

 
 
 

Changes in Gross Margin:
 
 

Generation
 
(172
)
Retail, Trading and Marketing
 
40

Other
 
(4
)
Total Change in Gross Margin
 
(136
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
86

Depreciation and Amortization
 
17

Taxes Other Than Income Taxes
 
7

Interest and Investment Income
 
(2
)
Interest Expense
 
4

Total Change in Expenses and Other
 
112

 
 
 

Income Tax Expense
 
6

 
 
 

Nine Months Ended September 30, 2015
 
$
360


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 certain cost of service for retail operations were as follows:

Generation decreased $172 million primarily due to lower capacity revenue due to the termination of the Power Supply Agreement between AGR and OPCo on May 31, 2015.
Retail, Trading and Marketing increased $40 million primarily due to favorable wholesale trading and marketing performance as well as an increase in retail volumes.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses decreased $86 million primarily due to a settlement and revision of certain asset retirement obligations and decreased plant outage and maintenance costs.
Depreciation and Amortization expenses decreased $17 million primarily due to reduced plant in-service.
Taxes Other Than Income Taxes decreased $7 million primarily due to a decrease in property taxes.
Income Tax Expense decreased $6 million primarily due to a decrease in pretax book income, partially offset by the recording of federal and state income tax adjustments.


33



AEP RIVER OPERATIONS

Third Quarter of 2015 Compared to Third Quarter of 2014

Earnings Attributable to AEP Common Shareholders from our AEP River Operations segment decreased from $11 million in 2014 to $4 million in 2015 primarily due to a loss on AEPRO's equity investment in IMT due to bankruptcy of an IMT customer.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

Earnings Attributable to AEP Common Shareholders from our AEP River Operations segment decreased from $17 million in 2014 to $16 million in 2015 primarily due to a loss on AEPRO's equity investment in IMT due to bankruptcy of an IMT customer, partially offset by lower fuel prices and reduced consumption.

CORPORATE AND OTHER

Third Quarter of 2015 Compared to Third Quarter of 2014

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from income of $11 million in 2014 to a loss of $9 million in 2015 primarily due to an increase in reserves for our captive insurance program as well as the impact of a 2014 tax adjustment.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from income of $4 million in 2014 to a loss of $13 million in 2015 primarily due to an increase in reserves for our captive insurance program as well as the impact of a 2014 tax adjustment.

AEP SYSTEM INCOME TAXES

Third Quarter of 2015 Compared to Third Quarter of 2014

Income Tax Expense increased $11 million primarily due to an increase in pretax book income and by the recording of federal and state income tax adjustments in the third quarter of 2015 compared to the third quarter of 2014, partially offset by the regulatory accounting treatment of state income taxes.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

Income Tax Expense increased $44 million primarily due to an increase in pretax book income and by the recording of federal and state income tax adjustments in 2015 compared to 2014, partially offset by the regulatory accounting treatment of state income taxes.


34



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, 2015
 
December 31, 2014
 
(dollars in millions)
Long-term Debt, including amounts due within one year (a)
$
19,507

 
51.3
%
 
$
18,684

 
50.7
%
Short-term Debt
782

 
2.1

 
1,346

 
3.6

Total Debt (a)
20,289

 
53.4

 
20,030

 
54.3

AEP Common Equity
17,699

 
46.6

 
16,820

 
45.7

Noncontrolling Interests
10

 

 
4

 

Total Debt and Equity Capitalization
$
37,998

 
100.0
%
 
$
36,854

 
100.0
%

(a)
Amounts include debt related to AEPRO that have been classified as Liabilities Held for Sale on the condensed balance sheets. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information.

Our ratio of debt-to-total capital improved from 54.3% as of December 31, 2014 to 53.4% as of September 30, 2015 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, 2015, 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, 2015, our available liquidity was approximately $3.6 billion as illustrated in the table below:
 
 
Amount
 
Maturity
 
 
(in millions)
 
 
Commercial Paper Backup:
 

 
 
 
Revolving Credit Facility
$
1,750

 
June 2017
 
Revolving Credit Facility
1,750

 
July 2018
Total
3,500

 
 
Cash and Cash Equivalents
178

 
 
Total Liquidity Sources
3,678

 
 
Less:
AEP Commercial Paper Outstanding
32

 
 
 
Letters of Credit Issued
33

 
 
 
 
 
 
 
Net Available Liquidity
$
3,613

 
 

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.


35



We use our commercial paper program to meet the short-term borrowing needs of our subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  The maximum amount of commercial paper outstanding during the first nine months of 2015 was $788 million.  The weighted-average interest rate for our commercial paper during 2015 was 0.45%.

Other Credit Facilities

We issue letters of credit under two uncommitted facilities totaling $150 million. As of September 30, 2015, the maximum future payment for letters of credit issued under the uncommitted facilities was $122 million with maturities ranging from October 2015 to September 2016. 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 expires in June 2017.

Debt Covenants and Borrowing Limitations

Our 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, 2015, this contractually-defined percentage was 50.6%. Nonperformance under these covenants could result in an event of default under these credit agreements. As of September 30, 2015, 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 and we manage our borrowings to stay within those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.56 per share in October 2015. 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.


36



Credit Ratings

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

CASH FLOW

Managing our cash flows is a major factor in maintaining our liquidity strength.
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
(in millions)
Cash and Cash Equivalents at Beginning of Period
$
163

 
$
118

Net Cash Flows from Operating Activities
3,910

 
3,715

Net Cash Flows Used for Investing Activities
(3,248
)
 
(3,079
)
Net Cash Flows Used for Financing Activities
(647
)
 
(560
)
Net Increase in Cash and Cash Equivalents
15

 
76

Cash and Cash Equivalents at End of Period
$
178

 
$
194


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,
 
2015
 
2014
 
(in millions)
Net Income
$
1,564

 
$
1,430

Depreciation and Amortization
1,528

 
1,418

Other
818

 
867

Net Cash Flows from Operating Activities
$
3,910

 
$
3,715


Net Cash Flows from Operating Activities were $3.9 billion in 2015 consisting primarily of Net Income of $1.6 billion and $1.5 billion of noncash Depreciation and Amortization. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. Deferred Income Taxes increased primarily due to provisions in the Taxpayer Relief Act of 2014 and an increase in tax/book temporary differences from operations. The reduction in Fuel, Materials and Supplies balances reflects a decrease in fuel inventory due to the cold winter weather and plants retired during the second quarter of 2015.

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.


37



Investing Activities
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
(in millions)
Construction Expenditures
$
(3,283
)
 
$
(2,897
)
Acquisitions of Nuclear Fuel
(53
)
 
(109
)
Acquisitions of Assets/Businesses
(1
)
 
(45
)
Other
89

 
(28
)
Net Cash Flows Used for Investing Activities
$
(3,248
)
 
$
(3,079
)

Net Cash Flows Used for Investing Activities were $3.2 billion in 2015 primarily due to Construction Expenditures for environmental, distribution and transmission investments.

Net Cash Flows Used for Investing Activities were $2.9 billion in 2014 primarily due to Construction Expenditures for environmental, distribution and transmission investments. We also purchased transmission assets for $38 million.

Financing Activities
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
(in millions)
Issuance of Common Stock, Net
$
68

 
$
63

Issuance of Debt, Net
236

 
195

Dividends Paid on Common Stock
(783
)
 
(736
)
Other
(168
)
 
(82
)
Net Cash Flows Used for Financing Activities
$
(647
)
 
$
(560
)

Net Cash Flows Used for Financing Activities in 2015 were $647 million. Our net debt issuances were $236 million. The net issuances included issuances of $2.1 billion of senior unsecured notes, $140 million of pollution control bonds and $757 million of other debt notes offset by retirements of $907 million of senior unsecured notes, $308 million of securitization bonds, $229 million of pollution control bonds and $687 of other debt notes and a decrease in short term borrowing of $564 million. We paid common stock dividends of $783 million. Other includes a make whole premium payment on the extinguishment of long-term debt of $93 million in addition to capital lease principal payments of $74 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 2014 were $560 million. Our net debt issuances were $195 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 $951 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.

In October 2015, KPCo drew the remaining $25 million on an existing $75 million variable rate credit facility due in 2018.

In October 2015, Transource Missouri drew $6 million on an existing $300 million variable rate credit facility due in 2018.


38



BUDGETED CONSTRUCTION EXPENDITURES

In July 2015, we increased our forecast for construction expenditures by $200 million to approximately $4.6 billion for 2015. The increase is primarily for transmission investment in the Vertically Integrated Utilities, Transmission and Distribution Utilities, and AEP Transmission Holdco segments.

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,
2015
 
December 31,
2014
 
(in millions)
Rockport Plant, Unit 2 Future Minimum Lease Payments
$
1,110

 
$
1,184

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 2014 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2014 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 2014 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

New Accounting Pronouncements Adopted During the First Quarter of 2015

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. We adopted ASU 2014-08 effective January 1, 2015.


39



Pronouncements Effective in the Future

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, determine 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 FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted for 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, 2018.

The FASB issued ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. We plan to adopt ASU 2015-01 effective January 1, 2016.

The FASB issued ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” to simplify the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. We include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. We intend to early adopt ASU 2015-03 for the 2015 Form 10-K.

The FASB issued ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. We plan to adopt ASU 2015-05 effective January 1, 2016.

The FASB issued ASU 2015-11 “Simplifying the Measurement of Inventory” to simplify the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. We plan to adopt ASU 2015-11 effective January 1, 2017.

The FASB issued ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. We have analyzed the impact of this new standard and determined that it will have no impact on the accounting of our contracts. Additionally, adoption has no impact on net income. We adopted ASU 2015-13 upon its issuance date.

40



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, consolidation policy and balance sheet classification of deferred taxes.  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 was exposed to FTR price risk as it related to RTO congestion during the June 2012 - May 2015 Ohio ESP period. Additional risks include energy procurement risk and 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, diesel 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 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.

41



The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2014:
MTM Risk Management Contract Net Assets (Liabilities)
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
Vertically
Integrated
Utilities
 
Transmission
and
Distribution
Utilities
 
Generation
&
Marketing
 
Total
 
(in millions)
Total MTM Risk Management Contract Net Assets as of December 31, 2014
$
36

 
$
46

 
$
140

 
$
222

Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period
(30
)
 
(5
)
 
(22
)
 
(57
)
Fair Value of New Contracts at Inception When Entered During the Period (a)

 

 
54

 
54

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

 

 
(17
)
 
(17
)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
23

 
(27
)
 

 
(4
)
Total MTM Risk Management Contract Net Assets as of September 30, 2015
$
29

 
$
14

 
$
155

 
198

Commodity Cash Flow Hedge Contracts
 
 
 

 
 

 
(17
)
Interest Rate and Foreign Currency Cash Flow Hedge Contracts
 
 
 

 
 

 
(1
)
Fair Value Hedge Contracts
 
 
 

 
 

 
1

Collateral Deposits
 
 
 

 
 

 
43

Elimination of Affiliated MTM Risk Management Contracts
 
 
 
 
 
 
(4
)
Total MTM Derivative Contract Net Assets as of September 30, 2015
 
 
 

 
 

 
$
220


(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.


42



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, 2015, our credit exposure net of collateral to sub investment grade counterparties was approximately 7%, 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, 2015, 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
 
$
727

 
$
1

 
$
726

 
2

 
$
269

Split Rating
 
25

 

 
25

 
1

 
25

Noninvestment Grade
 
1

 
1

 

 

 

No External Ratings:
 
 

 
 

 


 
 

 
 

Internal Investment Grade
 
123

 

 
123

 
3

 
66

Internal Noninvestment Grade
 
83

 
18

 
65

 
2

 
36

Total as of September 30, 2015
 
$
959

 
$
20

 
$
939

 
8

 
$
396

 
 
 
 
 
 
 
 
 
 
 
Total as of December 31, 2014
 
$
817

 
$
21

 
$
796

 
8

 
$
347


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, 2015, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

The following tables show the end, high, average and low market risk as measured by VaR for the periods indicated:

VaR Model
Trading Portfolio
Nine Months Ended
 
Twelve Months Ended
September 30, 2015
 
December 31, 2014
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
(in millions)
 
(in millions)
$

 
$
1

 
$

 
$

 
$

 
$
3

 
$
1

 
$


VaR Model
Non-Trading Portfolio
Nine Months Ended
 
Twelve Months Ended
September 30, 2015
 
December 31, 2014
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
(in millions)
 
(in millions)
$
1

 
$
2

 
$
1

 
$

 
$
2

 
$
3

 
$
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.

43



As our VaR calculation captures recent price movements, we also perform regular stress testing of the trading portfolio to understand our exposure to extreme price movements. We employ a historical-based method whereby the current trading 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.

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, 2015 and December 31, 2014, the estimated EaR on our debt portfolio for the following twelve months was $34 million and $33 million, respectively.

44




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2015 and 2014
(in millions, except per-share and share amounts)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
REVENUES
 
 
 
 
 
 
 
 
Vertically Integrated Utilities
 
$
2,436

 
$
2,432

 
$
7,082

 
$
7,217

Transmission and Distribution Utilities
 
1,164

 
1,163

 
3,378

 
3,388

Generation & Marketing
 
802

 
538

 
2,289

 
1,932

Other Revenues
 
30

 
28

 
90

 
22

TOTAL REVENUES
 
4,432

 
4,161

 
12,839

 
12,559

 
 
 
 
 
 
 
 
 
EXPENSES
 
 

 
 

 
 

 
 

Fuel and Other Consumables Used for Electric Generation
 
955

 
1,080

 
2,782

 
3,291

Purchased Electricity for Resale
 
731

 
449

 
2,050

 
1,560

Other Operation
 
691

 
685

 
1,955

 
1,985

Maintenance
 
312

 
313

 
923

 
929

Depreciation and Amortization
 
535

 
499

 
1,528

 
1,418

Taxes Other Than Income Taxes
 
248

 
230

 
733

 
679

TOTAL EXPENSES
 
3,472

 
3,256

 
9,971

 
9,862

 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
960

 
905

 
2,868

 
2,697

 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 

 
 

 
 

 
 

Interest and Investment Income
 
2

 
1

 
6

 
5

Carrying Costs Income
 
1

 
7

 
18

 
22

Allowance for Equity Funds Used During Construction
 
33

 
27

 
97

 
74

Interest Expense
 
(221
)
 
(217
)
 
(659
)
 
(650
)
 
 
 
 
 
 
 
 
 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
 
775

 
723

 
2,330

 
2,148

 
 
 
 
 
 
 
 
 
Income Tax Expense
 
275

 
264

 
827

 
783

Equity Earnings of Unconsolidated Subsidiaries
 
12

 
24

 
61

 
65

 
 
 
 
 
 
 
 
 
INCOME FROM CONTINUING OPERATIONS
 
512

 
483

 
1,564

 
1,430

 
 
 
 
 
 
 
 
 
INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX
 
8

 
11

 
18

 
16

 
 
 
 
 
 
 
 
 
NET INCOME
 
520

 
494

 
1,582

 
1,446

 
 
 
 
 
 
 
 
 
Net Income Attributable to Noncontrolling Interests
 
1

 
1

 
4

 
3

 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
519

 
$
493

 
$
1,578

 
$
1,443

 
 
 
 
 
 
 
 
 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
 
490,648,929

 
488,912,892

 
490,155,315

 
488,361,017

 
 
 
 
 
 
 
 
 
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS
 
$
1.04

 
$
0.99

 
$
3.18

 
$
2.92

BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS
 
$
0.02

 
$
0.02

 
$
0.04

 
$
0.03

TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
1.06

 
$
1.01

 
$
3.22

 
$
2.95

 
 
 
 
 
 
 
 
 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
 
490,800,335

 
488,970,647

 
490,411,020

 
488,597,178

 
 
 
 
 
 
 
 
 
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS
 
$
1.04

 
$
0.99

 
$
3.18

 
$
2.92

DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS
 
$
0.02

 
$
0.02

 
$
0.04

 
$
0.03

TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
1.06

 
$
1.01

 
$
3.22

 
$
2.95

 
 
 
 
 
 
 
 
 
CASH DIVIDENDS DECLARED PER SHARE
 
$
0.53

 
$
0.50

 
$
1.59

 
$
1.50

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 51.


45



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2015 and 2014
(in millions)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
Net Income
 
$
520

 
$
494

 
$
1,582

 
$
1,446

 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
 
 

 
 

 
 

 
 

Cash Flow Hedges, Net of Tax of $3 and $1 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $6 and $3 for the Nine Months Ended September 30, 2015 and 2014, Respectively
 
(6
)
 
(2
)
 
(11
)
 
6

Securities Available for Sale, Net of Tax of $1 and $0 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $1 and $0 for the Nine Months Ended September 30, 2015 and 2014, Respectively
 
(1
)
 

 
(1
)
 
1

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $1 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $0 and $2 for the Nine Months Ended September 30, 2015 and 2014, Respectively
 

 
1

 
1

 
3

 
 
 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
 
(7
)
 
(1
)
 
(11
)
 
10

 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
513

 
493

 
1,571

 
1,456

 
 
 
 
 
 
 
 
 
Total Comprehensive Income Attributable to Noncontrolling Interests
 
1

 
1

 
4

 
3

 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
512

 
$
492

 
$
1,567

 
$
1,453

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 51.


46



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 2015 and 2014
(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, 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

 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY - DECEMBER 31, 2014
510

 
$
3,313

 
$
6,204

 
$
7,406

 
$
(103
)
 
$
4

 
$
16,824

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Common Stock
1

 
9

 
59

 
 

 
 

 
 

 
68

Common Stock Dividends
 

 
 

 
 

 
(780
)
 
 

 
(3
)
 
(783
)
Other Changes in Equity
 

 
 

 
19

 
 
 
 

 
5

 
24

Net Income
 
 
 
 
 
 
1,578

 
 

 
4

 
1,582

Other Comprehensive Loss
 

 
 

 
 

 
 

 
(11
)
 
 

 
(11
)
Pension and OPEB Adjustment Related to Mitchell Plant
 
 
 
 
 
 
 
 
5

 
 
 
5

TOTAL EQUITY - SEPTEMBER 30, 2015
511

 
$
3,322

 
$
6,282

 
$
8,204

 
$
(109
)
 
$
10

 
$
17,709

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 51.


47



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2015 and December 31, 2014
(in millions)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2015
 
2014
CURRENT ASSETS
 
 

 
 

Cash and Cash Equivalents
 
$
178

 
$
163

Other Temporary Investments
(September 30, 2015 and December 31, 2014 Amounts Include $307 and $371, Respectively, Related to Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and EIS)
 
315

 
386

Accounts Receivable:
 
 

 
 

Customers
 
662

 
637

Accrued Unbilled Revenues
 
147

 
146

Pledged Accounts Receivable – AEP Credit
 
987

 
987

Miscellaneous
 
84

 
85

Allowance for Uncollectible Accounts
 
(27
)
 
(20
)
Total Accounts Receivable
 
1,853

 
1,835

Fuel
 
376

 
581

Materials and Supplies
 
729

 
736

Risk Management Assets
 
143

 
178

Regulatory Asset for Under-Recovered Fuel Costs
 
105

 
127

Margin Deposits
 
85

 
95

Assets Held for Sale
 
608

 
103

Prepayments and Other Current Assets
 
156

 
274

TOTAL CURRENT ASSETS
 
4,548

 
4,478

 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 

 
 

Electric:
 
 

 
 

Generation
 
25,665

 
25,727

Transmission
 
13,305

 
12,433

Distribution
 
17,812

 
17,157

Other Property, Plant and Equipment (September 30, 2015 and December 31, 2014 Amounts Include Plant to be Retired, Coal Mining and Nuclear Fuel, December 31, 2014 Amount Includes 2015 Plant Retirement)
 
4,036

 
5,074

Construction Work in Progress
 
4,008

 
3,215

Total Property, Plant and Equipment
 
64,826

 
63,606

Accumulated Depreciation and Amortization
 
19,588

 
19,971

TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
45,238

 
43,635

 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 

 
 

Regulatory Assets
 
4,950

 
4,264

Securitized Assets
 
1,841

 
2,072

Spent Nuclear Fuel and Decommissioning Trusts
 
2,047

 
2,096

Goodwill
 
53

 
53

Long-term Risk Management Assets
 
353

 
294

Assets Held for Sale
 

 
522

Deferred Charges and Other Noncurrent Assets
 
2,069

 
2,219

TOTAL OTHER NONCURRENT ASSETS
 
11,313

 
11,520

 
 
 
 
 
TOTAL ASSETS
 
$
61,099

 
$
59,633

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 51.


48



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2015 and December 31, 2014
(dollars in millions)
(Unaudited)
 
 
 
 
 
 
 
September 30,
 
December 31,
 
 
 
 
 
 
 
2015
 
2014
CURRENT LIABILITIES
 
 
 
 
Accounts Payable
 
 
 
 
 
 
$
1,274

 
$
1,258

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

 
744

Other Short-term Debt
 
 
 
 
 
 
32

 
602

Total Short-term Debt
 
 
 
 
 
 
782

 
1,346

Long-term Debt Due Within One Year
(September 30, 2015 and December 31, 2014 Amounts Include $424 and $431, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine)
 
 
1,826

 
2,500

Risk Management Liabilities
 
 
 
 
 
 
75

 
92

Customer Deposits
 
 
 
 
 
 
335

 
324

Accrued Taxes
 
 
 
 
 
 
748

 
863

Accrued Interest
 
 
 
 
 
 
236

 
238

Regulatory Liability for Over-Recovered Fuel Costs
 
 
 
 
74

 
55

Liabilities Held for Sale
 
 
 
 
 
 
474

 
85

Other Current Liabilities
 
 
 
 
 
 
1,234

 
1,206

TOTAL CURRENT LIABILITIES
 
 
 
 
 
 
7,058

 
7,967

 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
Long-term Debt
(September 30, 2015 and December 31, 2014 Amounts Include $2,004 and $2,260, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy and Sabine)
 
 
17,600

 
16,101

Long-term Risk Management Liabilities
 
 
 
 
 
 
201

 
131

Deferred Income Taxes
 
 
 
 
 
 
11,425

 
10,892

Regulatory Liabilities and Deferred Investment Tax Credits
 
 
3,762

 
3,892

Asset Retirement Obligations
 
 
 
 
 
 
1,944

 
1,951

Employee Benefits and Pension Obligations
 
 
 
 
 
 
535

 
630

Liabilities Held for Sale
 
 
 
 
 
 

 
350

Deferred Credits and Other Noncurrent Liabilities
 
 
865

 
895

TOTAL NONCURRENT LIABILITIES
 
 
 
 
 
 
36,332

 
34,842

 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 
 
 
 
43,390

 
42,809

 
 
 
 
 
 
 
 
 
 
Rate Matters (Note 4)
 
 
 
 
 
 

 

Commitments and Contingencies (Note 5)
 
 
 
 
 
 

 

 
 
 
 
 
 
 
 
 
 
EQUITY
 
 
 
 
Common Stock – Par Value – $6.50 Per Share:
 
 
 
 
 
 
 
 
 
 
 
2015
 
2014
 
 
 
 
 
Shares Authorized
 
600,000,000
 
600,000,000
 
 
 
 
 
Shares Issued
 
511,141,256
 
509,739,159
 
 
 
 
 
(20,336,592 Shares were Held in Treasury as of September 30, 2015 and December 31, 2014)
 
 
3,322

 
3,313

Paid-in Capital
 
 
 
 
 
 
6,282

 
6,204

Retained Earnings
 
 
 
 
 
 
8,204

 
7,406

Accumulated Other Comprehensive Income (Loss)
 
 
(109
)
 
(103
)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY
 
 
17,699

 
16,820

 
 
 
 
 
 
 
 
 
 
Noncontrolling Interests
 
 
 
 
 
 
10

 
4

 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY
 
 
 
 
 
 
17,709

 
16,824

 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 
 
 
 
 
 
$
61,099

 
$
59,633

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 51.

49



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2015 and 2014
(in millions)
(Unaudited)
 
 
Nine Months Ended September 30,
 
 
2015
 
2014
OPERATING ACTIVITIES
 
 

 
 

Net Income
 
$
1,582

 
$
1,446

Income from Discontinued Operations
 
18

 
16

Income from Continuing Operations
 
1,564

 
1,430

Adjustments to Reconcile Income from Continuing Operations to Net Cash Flows from Operating Activities:
 
 
 
 
Depreciation and Amortization
 
1,528

 
1,418

Deferred Income Taxes
 
529

 
385

Carrying Costs Income
 
(18
)
 
(22
)
Allowance for Equity Funds Used During Construction
 
(97
)
 
(74
)
Mark-to-Market of Risk Management Contracts
 
18

 
15

Amortization of Nuclear Fuel
 
102

 
114

Pension Contributions to Qualified Plan Trust
 
(92
)
 
(70
)
Property Taxes
 
247

 
220

Fuel Over/Under-Recovery, Net
 
93

 
(77
)
Deferral of Ohio Capacity Costs, Net
 
35

 
(106
)
Change in Other Noncurrent Assets
 
(106
)
 
(41
)
Change in Other Noncurrent Liabilities
 
(1
)
 
271

Changes in Certain Components of Working Capital:
 
 
 
 
Accounts Receivable, Net
 
(18
)
 
(19
)
Fuel, Materials and Supplies
 
194

 
222

Accounts Payable
 
(13
)
 
(40
)
Accrued Taxes, Net
 
(68
)
 
20

Other Current Assets
 
11

 

Other Current Liabilities
 
2

 
69

Net Cash Flows from Operating Activities
 
3,910

 
3,715

 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
Construction Expenditures
 
(3,283
)
 
(2,897
)
Change in Other Temporary Investments, Net
 
81

 
37

Purchases of Investment Securities
 
(1,489
)
 
(791
)
Sales of Investment Securities
 
1,437

 
746

Acquisitions of Nuclear Fuel
 
(53
)
 
(109
)
Acquisitions of Assets/Businesses
 
(1
)
 
(45
)
Other Investing Activities
 
60

 
(20
)
Net Cash Flows Used for Investing Activities
 
(3,248
)
 
(3,079
)
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
Issuance of Common Stock, Net
 
68

 
63

Issuance of Long-term Debt
 
2,931

 
1,206

Change in Short-term Debt, Net
 
(564
)
 
525

Retirement of Long-term Debt
 
(2,131
)
 
(1,536
)
Make Whole Premium on Extinguishment of Long-term Debt
 
(93
)
 

Principal Payments for Capital Lease Obligations
 
(74
)
 
(85
)
Dividends Paid on Common Stock
 
(783
)
 
(736
)
Other Financing Activities
 
(1
)
 
3

Net Cash Flows Used for Financing Activities
 
(647
)
 
(560
)
 
 
 
 
 
Net Increase in Cash and Cash Equivalents
 
15

 
76

Cash and Cash Equivalents at Beginning of Period
 
163

 
118

Cash and Cash Equivalents at End of Period
 
$
178

 
$
194

 
 
 
 
 
CASH FLOWS FROM DISCONTINUED OPERATIONS
 
 
 
 
Operating Activities
 
$
10

 
$
10

Investing Activities
 
2

 
(2
)
Financing Activities
 
(12
)
 
(8
)
Net Change in Cash and Cash Equivalents from Discontinued Operations
 

 

Cash and Cash Equivalents from Discontinued Operations - Beginning of Period
 

 

Cash and Cash Equivalents from Discontinued Operations - End of Period
 
$

 
$

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 51.


50



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
Disposition, Assets and Liabilities Held for Sale and Discontinued Operations
Benefit Plans
Business Segments
Derivatives and Hedging
Fair Value Measurements
Income Taxes
Financing Activities
Variable Interest Entities
Property, Plant and Equipment
Disposition Plant Severance


51



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, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015.  The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2014 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 20, 2015.

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, KPCo and WPCo 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 on January 1, 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.


52



Earnings Per Share (EPS)

Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period.  Diluted EPS 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,
 
2015
 
2014
 
(in millions, except per share data)
 
 

 
$/share
 
 
 
$/share
Income from Continuing Operations
$
512

 
 
 
$
483

 
 
Less: Net Income Attributable to Noncontrolling Interests
1

 
 
 
1

 
 
Earnings Attributable to AEP Common Shareholders from Continuing Operations
$
511

 
 

 
$
482

 
 

 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares Outstanding
490.6

 
$
1.04

 
488.9

 
$
0.99

Weighted Average Dilutive Effect of Restricted Stock Units
0.2

 

 
0.1

 

Weighted Average Number of Diluted Shares Outstanding
490.8

 
$
1.04

 
489.0

 
$
0.99

 
Nine Months Ended September 30,
 
2015
 
2014
 
(in millions, except per share data)
 
 

 
$/share
 
 
 
$/share
Income from Continuing Operations
$
1,564

 
 
 
$
1,430

 
 
Less: Net Income Attributable to Noncontrolling Interests
4

 
 
 
3

 
 
Earnings Attributable to AEP Common Shareholders from Continuing Operations
$
1,560

 
 
 
$
1,427

 
 
 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares Outstanding
490.2

 
$
3.18

 
488.4

 
$
2.92

Weighted Average Dilutive Effect of Restricted Stock Units
0.2

 

 
0.2

 

Weighted Average Number of Diluted Shares Outstanding
490.4

 
$
3.18

 
488.6

 
$
2.92


There were no antidilutive shares outstanding as of September 30, 2015 and 2014.

Supplementary Cash Flow Information
 
 
Nine Months Ended September 30,
Cash Flow Information
 
2015
 
2014
 
 
(in millions)
Cash Paid (Received) for:
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
639

 
$
649

Net Cash Paid for Income Taxes
 
116

 
109

Noncash Investing and Financing Activities:
 
 
 
 
Noncash Acquisitions Under Capital Leases
 
97

 
80

Construction Expenditures Included in Current Liabilities as of September 30,
 
579

 
515

Construction Expenditures Included in Noncurrent Liabilities as of September 30,
 
66

 

Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,
 
31

 



53



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.

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

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

In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine 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 FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. 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, 2018.

ASU 2015-01 “Income Statement Extraordinary and Unusual Items” (ASU 2015-01)

In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. We plan to adopt ASU 2015-01 effective January 1, 2016.

ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03)

In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. We include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt.


54



The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. We intend to early adopt ASU 2015-03 for the 2015 Form 10-K.

ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05)

In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. We plan to adopt ASU 2015-05 effective January 1, 2016.

ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11)

In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. We plan to adopt ASU 2015-11 effective January 1, 2017.

ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13)

In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale.

The new accounting guidance is effective upon issuance and applied prospectively. We have analyzed the impact of this new standard and determined that it will have no impact on the accounting of our contracts. Additionally, adoption has no impact on net income. We adopted ASU 2015-13 upon its issuance date.



55



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, 2015 and 2014.  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, 2015
 
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, 2015
$
(5
)
 
$
(18
)
 
$
8

 
$
(87
)
 
$
(102
)
Change in Fair Value Recognized in AOCI
(3
)
 

 
(1
)
 

 
(4
)
Amounts Reclassified from AOCI
(3
)
 

 

 

 
(3
)
Net Current Period Other Comprehensive Loss
(6
)
 

 
(1
)
 

 
(7
)
Balance in AOCI as of September 30, 2015
$
(11
)
 
$
(18
)
 
$
7

 
$
(87
)
 
$
(109
)

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 (Loss)
(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 Nine Months Ended September 30, 2015
 
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, 2014
$
1

 
$
(19
)
 
$
8

 
$
(93
)
 
$
(103
)
Change in Fair Value Recognized in AOCI
(2
)
 

 
(1
)
 

 
(3
)
Amounts Reclassified from AOCI
(10
)
 
1

 

 
1

 
(8
)
Net Current Period Other Comprehensive Income (Loss)
(12
)
 
1

 
(1
)
 
1

 
(11
)
Pension and OPEB Adjustment Related to Mitchell Plant

 

 

 
5

 
5

Balance in AOCI as of September 30, 2015
$
(11
)
 
$
(18
)
 
$
7

 
$
(87
)
 
$
(109
)


56



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
)

Reclassifications from Accumulated Other Comprehensive Income

The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2015 and 2014.  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, 2015 and 2014
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Three Months Ended September 30,
 
 
2015
 
2014
Gains and Losses on Cash Flow Hedges
 
(in millions)
Commodity:
 
 

 
 
Generation & Marketing Revenues
 
$
(19
)
 
$

Purchased Electricity for Resale
 
14

 
(9
)
Subtotal  Commodity
 
(5
)
 
(9
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 

 
2

Subtotal  Interest Rate and Foreign Currency
 

 
2

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(5
)

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

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

 
7

Reclassifications from AOCI, before Income Tax (Expense) Credit
 

 
2

Income Tax (Expense) Credit
 

 
1

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

 
1

 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(3
)
 
$
(4
)


57



Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2015 and 2014
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Nine Months Ended September 30,
 
 
2015
 
2014
Gains and Losses on Cash Flow Hedges
 
(in millions)
Commodity:
 
 

 
 
Generation & Marketing Revenues
 
$
(36
)
 
$

Purchased Electricity for Resale
 
20

 
20

Regulatory Assets/(Liabilities), Net (a)
 

 
(3
)
Subtotal  Commodity
 
(16
)
 
17

 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
1

 
6

Subtotal  Interest Rate and Foreign Currency
 
1

 
6

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(15
)

23

Income Tax (Expense) Credit
 
(6
)
 
9

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(9
)
 
14

 
 
 
 
 
Pension and OPEB
 
 

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

 
21

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
1

 
6

Income Tax (Expense) Credit
 

 
3

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

 
3

 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(8
)
 
$
17


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


58



4.  RATE MATTERS

As discussed in the 2014 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2014 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 2015 and updates the 2014 Annual Report.

Regulatory Assets Pending Final Regulatory Approval
 
 
September 30,
 
December 31,
 
 
2015
 
2014
 Noncurrent Regulatory Assets
 
(in millions)
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
Storm Related Costs
 
$
24

 
$
20

Material and Supplies Related to Retired Plants
 
20

 

West Virginia Vegetation Management Program
 

 
20

Regulatory Assets Currently Not Earning a Return
 
 

 
 

Asset Retirement Obligation Costs Related to Retired Plants
 
59

 

Virginia Peak Demand Reduction/Energy Efficiency
 
12

 
9

Ormet Special Rate Recovery Mechanism
 
10

 
10

Storm Related Costs
 
7

 
100

Carbon Capture and Storage Product Validation Facility
 

 
13

IGCC Pre-Construction Costs
 

 
11

Other Regulatory Assets Pending Final Regulatory Approval
 
27

 
43

Total Regulatory Assets Pending Final Regulatory Approval
$
159

 
$
226


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. 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.

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 appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. In September 2015, the Supreme Court of Ohio denied the IEU's request for reconsideration and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate.


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June 2012 – May 2015 ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that established 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 $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, which has scheduled oral arguments for the fourth quarter of 2015.

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 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 2015, the PUCO issued an order that approved, with modifications, OPCo's July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00/MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million. In May 2015, the PUCO granted intervenors requests for rehearing. As of September 30, 2015, OPCo's net deferred capacity costs balance of $392 million, including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. Through September 30, 2015, OPCo has collected $183 million in deferred capacity costs, and related carrying charges.

In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. 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 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015.

In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. 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.

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 October 2014, the independent auditor, selected by the PUCO, 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/MW day capacity charge, the independent auditor has recommended 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 disagrees with the findings in the audit report.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.


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June 2015 - May 2018 ESP Including PPA Application

In December 2013, OPCo filed an application with the PUCO to approve an ESP that included 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 also included 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 PPA. 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 February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo's and various intervenors' requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider.

In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. A hearing at the PUCO related to the PPA commenced in September 2015. In October 2015, the PUCO staff submitted testimony that opposed the PPA application as currently proposed but concluded that, with changes, a PPA could be in the public interest.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, 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 June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements.

Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation and 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.


61



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 September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. 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.

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 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (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, 2015, 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.

SWEPCo Rate Matters

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 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,

62



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, 2015, the net book value of Welsh Plant, Unit 2 was $83 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 was 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 and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, 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 SWEPCo's 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 review base rates in 2014 and 2015 and that SWEPCo recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million, primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, 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.  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 purchased power agreement attributable to Louisiana customers.  In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2015 Louisiana Formula Rate Filing

In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC.  The filing included a $14 million annual increase, which was effective August 2015.  This increase is subject to LPSC staff review and is subject to refund.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


63



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 2024 for Welsh Plant, Units 1 and 3 will cost approximately $700 million, excluding AFUDC.  As of September 30, 2015, SWEPCo has incurred costs of $303 million, including AFUDC, and has remaining contractual construction obligations of $62 million related to these projects.  SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of September 30, 2015, the net book value of Welsh Plant, Units 1 and 3 was $529 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

2014 West Virginia Base Rate Case

In May 2015, the WVPSC issued an order on APCo and WPCo's base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $99 million based upon a 9.75% return on common equity. The order included a delayed billing of $25 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $25 million delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $45 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $89 million in previously recorded regulatory assets, which will predominantly be recovered over five years.

2015 Virginia Regulatory Asset Proceeding

In January 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets. In February and March 2015, briefs related to this proceeding were filed by various parties. As of September 30, 2015, APCo’s authorized regulatory assets under review in this proceeding were $11 million. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition.

New Virginia Legislation Affecting Biennial Reviews

In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA.

PSO Rate Matters

2015 Oklahoma Base Rate Case

In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million, which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base

64



rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million, excluding AFUDC. As of September 30, 2015, PSO has incurred costs of $162 million related to these projects, including AFUDC.
  
In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million, will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of September 30, 2015, the net book value of Northeastern Plant, Unit 4 was $94 million, before cost of removal, including materials and supplies inventory and CWIP.

In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million, based upon returns on common equity ranging from 8.75% to 9.3%, and increases to depreciation expense ranging from $23 million to $46 million. Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certain intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC are scheduled for December 2015.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2014 Oklahoma Base Rate Case

In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for 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 provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) 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 and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014.

I&M Rate Matters

Tanners Creek Plant

In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon 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. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates.


65



In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval.

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 for eligible transmission, distribution and storage system improvements totaling $787 million. In April 2015, I&M filed a notice with the IURC to exclude $117 million related to certain projects. In September 2015, the IURC granted I&M's motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals.

KPCo Rate Matters

Plant Transfer

In October 2013, the KPSC issued an order that approved a modified settlement agreement which included the approval to transfer to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. 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 of the order with the Franklin County Circuit Court. In April 2015, the Franklin County Circuit Court issued an order that affirmed the KPSC's October 2013 order. In May 2015, the Attorney General filed an appeal with the Franklin County Circuit Court of the April 2015 order that had affirmed the KPSC's order.

Consistent with KPCo’s December 2012 plant transfer filing that was approved by the KPSC, Big Sandy Plant, Unit 2 was retired in May 2015. Upon retirement, $194 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Big Sandy Plant, Unit 2 and the related asset retirement obligations, costs of removal and materials and supplies. These regulatory assets will be amortized over 25 years, effective July 2015.

If any part of the KPSC order is overturned, it could reduce future net income and cash flows and impact financial condition.

Kentucky Fuel Adjustment Clause Review

In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owned and operated both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court. In September 2015, the Franklin County Circuit Court issued an order that dismissed all appeals filed related to this FAC review, as agreed to by the parties to the stipulation agreement in the "2014 Kentucky Base Rate Case" discussed below.

2014 Kentucky Base Rate Case

In December 2014, KPCo filed a request with the KPSC for a net increase in rates of $70 million. In April 2015, a non-unanimous stipulation agreement between KPCo and certain intervenors was filed with the KPSC. The parties to the stipulation recommended a net revenue increase of $45 million, which consisted of a $68 million increase in rider rates, offset by a $23 million decrease in annual base rates, to be effective July 2015. The proposed net increase reflects KPCo's ownership interest in the Mitchell Plant, riders to recover the Big Sandy Plant retirement and operational costs and the inclusion of an environmental compliance plan.  Additionally, the agreement included (a) recovery of $12 million of deferred storm costs, (b) any difference between the actual off-system sales margins and the $15 million

66



included in the proposed annual base rates to be shared with 75% to the customer and 25% to KPCo and (c) dismissal of the KPCo and the Kentucky Industrial Utility Customers appeals of the KPSC order in the KPCo fuel adjustment clause review. See "Kentucky Fuel Adjustment Clause Review" discussed above.

In June 2015, the KPSC issued an order that approved a modified stipulation agreement. The order approved a net revenue increase of $45 million, as proposed in the stipulation agreement, and contained modifications that included (a) approval to recover $2 million of IGCC and certain carbon capture study costs, both over 25 years, (b) no deferral of certain PJM costs and (c) denial of the recovery of certain potential purchased power costs through a rider.

KGPCo Rate Matters

2015 Kingsport Base Rate Case

In September 2015, KGPCo filed a request with the TRA to increase base rates by $12 million annually based upon a proposed return on common equity of 10.66% with the new rates expected to be implemented by July 2016. If KGPCo does not recover its costs, 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.  We accrue contingent liabilities only when we conclude that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When we determine that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, we disclose such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent our maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.

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 2014 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, 2015, the maximum future payments for letters of credit issued under the revolving credit facilities were $33 million with maturities ranging from December 2015 to November 2016.

We issue letters of credit under two uncommitted facilities totaling $150 million.  As of September 30, 2015, the maximum future payments for letters of credit issued under the uncommitted facilities were $122 million with maturities ranging from October 2015 to September 2016. 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 2016 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 $58 million.  Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation.  As of September 30, 2015, SWEPCo has collected $65 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 $49 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, 2015, 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, 2015, the maximum potential loss for these lease agreements was $35 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 $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2015.

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 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 $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 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed

69



remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of September 30, 2015, I&M's accrual for all of these sites is approximately $8 million.  As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the 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. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing.  In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. Plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. We will continue to defend against the remaining 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, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue. AEP also subsequently filed a separate 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

70



Court on the preemption issue. Oral argument occurred in January 2015. In April 2015, the U.S. Supreme Court affirmed the judgment of the U.S. Court of Appeals for the Ninth Circuit on the preemption issue, holding that the plaintiffs' state antitrust claims were not preempted by the Natural Gas Act. The U.S. Supreme Court denied AEP's petition for review of the personal jurisdiction issue shortly thereafter. The cases have been remanded to the district court for further proceedings. 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.

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 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. We will continue to defend the case. We do not believe a loss is probable. If there is an unfavorable outcome contrary to our expectations, we estimate possible losses of up to $30 million.

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. As a result of a mediation held in October 2014, the parties reached an agreement in principle, subject to final documentation and preliminary and final court approval. In April 2015, we filed a motion with the court for preliminary approval of the settlement. In June 2015, the court granted preliminary approval of the settlement. In September 2015, the court granted final approval of the settlement, reserving decision on the appropriate fee for plaintiff's counsel.

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.  In August 2015, the court denied our motion. We appealed that decision to the West Virginia Supreme Court. We will continue to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.


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6.  DISPOSITION, ASSETS AND LIABILITIES HELD FOR SALE AND DISCONTINUED OPERATIONS

DISPOSITION

2015

Muskingum River Plant (Generation & Marketing Segment)

In August 2015, AGR sold its retired Muskingum River Plant site including its associated asset retirement obligations to a nonaffiliated party.  AGR paid $48 million and the nonaffiliated party took ownership of the Muskingum River Plant site assets and assumed responsibility for environmental liabilities and AROs, including ash pond closure, asbestos abatement and decommissioning and demolition.  As a result of the sale, a net gain of $32 million was recognized and recorded in Other Operation on the condensed consolidated statements of income.  The cash paid was recorded in Operating Activities on the condensed consolidated statements of cash flows.  

ASSETS AND LIABILITIES HELD FOR SALE

AEPRO (AEP River Operations Segment)

During the third quarter of 2015, we evaluated bids from prospective buyers, selected a buyer and received approval from AEP's Board of Directors to proceed with the sale to the nonaffiliated party.  In October 2015, we signed an agreement to sell our commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party.  The sale of AEPRO is subject to regulatory approval including federal clearance pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976.  Upon close of the sale, the nonaffiliated party will acquire AEPRO by purchasing all of the common stock of AEP Resources, Inc., the parent company of AEPRO.  The nonaffiliated party will assume certain assets and liabilities of AEPRO, excluding the equity method investment in IMT, pension and benefit assets and liabilities and debt obligations.  We will retain ownership of our captive barge fleet that delivers coal to the company's regulated coal-fueled power plant units owned or leased by AEGCo, APCo, I&M, KPCo and WPCo.  We signed a contract with the nonaffiliated party to dispatch and schedule our captive barge fleet for the company's regulated coal-fueled power plant units.  We also contracted with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2016.  The sale is expected to close in the fourth quarter of 2015.

Upon evaluation, management concluded that the AEPRO business met the classification as held for sale in the third quarter of 2015.  Accordingly, AEPRO's assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on our condensed consolidated balance sheets as of September 30, 2015 and December 31, 2014 and as shown in the following table:
 
 
September 30, 2015
 
December 31, 2014
Assets:
 
(in millions)
Accounts Receivable
 
$
55

 
$
91

Property, Plant and Equipment  Net
 
506

 
482

Other Classes of Assets That Are Not Major
 
47

 
52

Total Assets Classified as Held for Sale on the Condensed Consolidated Balance Sheets
 
$
608


$
625

 
 
 
 
 
Liabilities:
 
 
 
 
Long-term Debt
 
$
81

 
$
83

Obligations Under Capital Leases
 
228

 
189

Other Classes of Liabilities That Are Not Major
 
165

 
163

Total Liabilities Classified as Held for Sale on the Condensed Consolidated Balance Sheets
 
$
474

 
$
435



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DISCONTINUED OPERATIONS

Management periodically assesses the overall AEP business model and makes decisions regarding our continued support and funding of our various businesses and operations.  When it is determined that we will seek to exit a particular business or activity and we have met the accounting requirements for reclassification, we will reclassify the operations of those businesses or operations as discontinued operations.  The assets and liabilities of these discontinued operations are classified as Assets Held for Sale and Liabilities Held for Sale until the time they are sold.  In the third quarter of 2015, AEPRO was determined to be discontinued operations and has been classified as such for third quarter 2015 reporting.  Results of operations of AEPRO have been classified as discontinued operations in our condensed consolidated statements of income for the three and nine months ended September 30, 2015 and 2014 as shown in the following table:
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
 
 
 
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Other Revenues
 
$
129

 
$
141

 
$
372

 
$
435

 
 
 
 
 
 
 
 
 
Other Operation Expense
 
96

 
102

 
273

 
342

Maintenance Expense
 
4

 
8

 
20

 
24

Depreciation and Amortization Expense
 
9

 
8

 
27

 
23

Other Expense
 
8

 
7

 
24

 
22

Total Expenses
 
117

 
125

 
344

 
411

 
 
 
 
 
 
 
 
 
Pretax Income of Discontinued Operations
 
12


16


28


24

Income Tax Expense
 
4

 
5

 
10

 
8

Total Income on Discontinued Operations as Presented on the Condensed Consolidated Statements of Income
 
$
8


$
11


$
18


$
16



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7.  BENEFIT PLANS

We sponsor a qualified pension plan and two unfunded nonqualified pension plans. Substantially all of our employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. We sponsor OPEB plans to provide health and life insurance benefits for retired employees.

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, 2015 and 2014:
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Service Cost
$
23

 
$
18

 
$
3

 
$
4

Interest Cost
51

 
55

 
15

 
16

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

 
1

 
(18
)
 
(18
)
Amortization of Net Actuarial Loss
27

 
31

 
5

 
6

Net Periodic Benefit Cost (Credit)
$
33

 
$
40

 
$
(23
)
 
$
(20
)
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Service Cost
$
70

 
$
54

 
$
9

 
$
11

Interest Cost
154

 
166

 
43

 
50

Expected Return on Plan Assets
(206
)
 
(196
)
 
(83
)
 
(84
)
Amortization of Prior Service Cost (Credit)
2

 
2

 
(52
)
 
(52
)
Amortization of Net Actuarial Loss
80

 
93

 
14

 
17

Net Periodic Benefit Cost (Credit)
$
100

 
$
119

 
$
(69
)
 
$
(58
)


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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.

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 and capacity to serve SSO customers and provides transmission and distribution services 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.
In October 2015, we signed an agreement to sell AEPRO to a nonaffiliated party. The AEP River Operations segment is comprised entirely of AEPRO. However, we will retain AEPRO's investment in IMT. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information.

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.


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The tables below present our reportable segment income statement information for the three and nine months ended September 30, 2015 and 2014 and reportable segment balance sheet information as of September 30, 2015 and December 31, 2014.  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, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 

 
 

 
 

 
 

 
 

 
 

 
 
 
 

External Customers
 
$
2,436

 
$
1,164

 
$
27

 
$
802

 
$

 
$
3

 
$

(c)
$
4,432

Other Operating Segments
 
35

 
25

 
61

 
33

 

 
21

 
(175
)
 

Total Revenues
 
$
2,471

 
$
1,189

 
$
88

 
$
835

 
$

 
$
24

 
$
(175
)
 
$
4,432


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (Loss) from Continuing Operations
 
$
275

 
$
113

 
$
46

 
$
91

 
$
(4
)
 
$
(9
)
 
$

 
$
512

Income from Discontinued Operations, Net of Tax
 

 

 

 

 
8

 

 

 
8

Net Income (Loss)
 
$
275

 
$
113

 
$
46

 
$
91

 
$
4

 
$
(9
)
 
$

 
$
520

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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)
$

 
$
7

 
$

(c)
$
4,161

Other Operating Segments
 
18

(b)
68

 
34

 
363

(b)

 
19

 
(502
)
 

Total Revenues
 
$
2,450

 
$
1,231

 
$
55

 
$
901

 
$

 
$
26

 
$
(502
)
 
$
4,161

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income from Continuing Operations
 
$
220

 
$
92

 
$
43

 
$
117

 
$

 
$
11

 
$

 
$
483

Income from Discontinued Operations, Net of Tax
 

 

 

 

 
11

 

 

 
11

Net Income
 
$
220

 
$
92

 
$
43

 
$
117

 
$
11

 
$
11

 
$

 
$
494



76



 
 
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, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 

 
 

 
 
 
 

 
 

 
 

 
 

 
 

External Customers
 
$
7,082


$
3,378

 
$
74

 
$
2,289

 
$

 
$
16

 
$

(c)
$
12,839

Other Operating Segments
 
77

 
142

 
171

 
517

 

 
58

 
(965
)
 

Total Revenues
 
$
7,159

 
$
3,520

 
$
245

 
$
2,806

 
$

 
$
74

 
$
(965
)
 
$
12,839

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (Loss) from Continuing Operations
 
$
783

 
$
288

 
$
148

 
$
360

 
$
(2
)
 
$
(13
)
 
$

 
$
1,564

Income from Discontinued Operations, Net of Tax
 

 

 

 

 
18

 

 

 
18

Net Income (Loss)
 
$
783

 
$
288

 
$
148

 
$
360

 
$
16

 
$
(13
)
 
$

 
$
1,582

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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)
$

 
$
19

 
$
(51
)
(c)
$
12,559

Other Operating Segments
 
71

(b)
192

 
86

 
1,133

(b)

 
55

 
(1,537
)
 

Total Revenues
 
$
7,288

 
$
3,580

 
$
140

 
$
3,065

 
$

 
$
74

 
$
(1,588
)
 
$
12,559

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income from Continuing Operations
 
$
654

 
$
279

 
$
114

 
$
378

 
$
1

 
$
4

 
$

 
$
1,430

Income from Discontinued Operations, Net of Tax
 

 

 

 

 
16

 

 

 
16

Net Income
 
$
654

 
$
279

 
$
114

 
$
378

 
$
17

 
$
4

 
$

 
$
1,446



77



 
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, 2015
 

 
 

 
 

 
 

 
 
 
 
 

 
 

 
 

 
Total Property, Plant and Equipment
$
39,981

 
$
13,707

 
$
3,594

 
$
7,474

 
$

 
 
$
349

 
$
(279
)
(d)
$
64,826

 
Accumulated Depreciation and Amortization
12,483

 
3,603

 
43

 
3,390

 

 
 
178

 
(109
)
(d)
19,588

 
Total Property, Plant and Equipment - Net
$
27,498

 
$
10,104

 
$
3,551

 
$
4,084

 
$

 
 
$
171

 
$
(170
)
(d)
$
45,238

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets Held for Sale
$

 
$

 
$

 
$

 
$
608

 
 
$

 
$

 
$
608

 
Total Assets
35,272

 
14,441

 
4,362

 
5,531

 
772

(f)
 
21,810

 
(21,089
)
(d) (e)
61,099

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt Due Within One Year:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliated
$

 
$

 
$

 
$

 
$

 
 
$

 
$

 
$

 
Nonaffiliated
949

 
724

 

 
151

 

 
 
2

 

 
1,826

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliated
20

 

 

 
32

 

 
 

 
(52
)
 

 
Nonaffiliated
9,900

 
4,888

 
1,323

 
641

 

 
 
848

 

 
17,600

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Long-term Debt
$
10,869

 
$
5,612

 
$
1,323

 
$
824

 
$

 
 
$
850

 
$
(52
)
 
$
19,426

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities Held for Sale
$

 
$

 
$

 
$

 
$
474

 
 
$

 
$

 
$
474

(g)


78



 
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, 2014
 

 
 

 
 

 
 

 
 
 
 
 

 
 

 
 

 
Total Property, Plant and Equipment
$
39,402

 
$
13,024

 
$
2,714

 
$
8,394

 
$

 
 
$
343

 
$
(271
)
(d)
$
63,606

 
Accumulated Depreciation and Amortization
12,773

 
3,481

 
25

 
3,603

 

 
 
188

 
(99
)
(d)
19,971

 
Total Property, Plant and Equipment - Net
$
26,629

 
$
9,543

 
$
2,689

 
$
4,791

 
$

 
 
$
155

 
$
(172
)
(d)
$
43,635

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets Held for Sale
$

 
$

 
$

 
$

 
$
625

 
 
$

 
$

 
$
625

 
Total Assets
33,750

 
14,495

 
3,575

 
6,329

 
749

(f)
 
21,081

 
(20,346
)
(d) (e)
59,633

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt Due Within One Year:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliated
$
111

 
$

 
$

 
$
86

 
$

 
 
$

 
$
(197
)
 
$

 
Nonaffiliated
1,352

 
405

 

 
740

 

 
 
3

 

 
2,500

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliated
20

 

 

 
32

 

 
 

 
(52
)
 

 
Nonaffiliated
8,634

 
5,256

 
1,153

 
217

 

 
 
841

 

 
16,101

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Long-term Debt
$
10,117

 
$
5,661

 
$
1,153

 
$
1,075

 
$

 
 
$
844

 
$
(249
)
 
$
18,601

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities Held for Sale
$

 
$

 
$

 
$

 
$
435

 
 
$

 
$

 
$
435

(g)

(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 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.
(f)
Amounts include intercompany advances to affiliates and intercompany accounts receivable that will be settled prior to or upon the close of the sale of AEPRO.
(g)
Amounts include debt related to AEPRO. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information.

79



9.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

We are exposed to certain market risks as a major power producer and participant in the wholesale electricity, natural gas, coal and emission allowance markets. 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, 2015 and December 31, 2014:

Notional Volume of Derivative Instruments
 
 
Volume
 
 
 
 
September 30,
2015
 
December 31,
2014
 
Unit of
Measure
Primary Risk Exposure
 
(in millions)
 
 
Commodity:
 
 
 
 

 
 
Power
 
371

 
334

 
MWhs
Coal
 
4

 
3

 
Tons
Natural Gas
 
46

 
106

 
MMBtus
Heating Oil and Gasoline
 
9

 
6

 
Gallons
Interest Rate
 
$
114

 
$
152

 
USD
 
 
 
 
 
 
 
Interest Rate and Foreign Currency
 
$
560

 
$
815

 
USD


80



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 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. 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 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.


81



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, 2015 and December 31, 2014 condensed balance sheets, we netted $4 million and $4 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $47 million and $35 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, 2015 and December 31, 2014:

Fair Value of Derivative Instruments
September 30, 2015
 
 
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
 
$
311

 
$
9

 
$
2

 
$
322

 
$
(179
)
 
$
143

Long-term Risk Management Assets
 
443

 
3

 

 
446

 
(93
)
 
353

Total Assets
 
754

 
12

 
2

 
768

 
(272
)
 
496

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
267

 
7

 
1

 
275

 
(200
)
 
75

Long-term Risk Management Liabilities
 
293

 
22

 
1

 
316

 
(115
)
 
201

Total Liabilities
 
560

 
29

 
2

 
591

 
(315
)
 
276

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
194

 
$
(17
)
 
$

 
$
177

 
$
43

 
$
220

 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 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
 
$
392

 
$
30

 
$
3

 
$
425

 
$
(247
)
 
$
178

Long-term Risk Management Assets
 
367

 
3

 

 
370

 
(76
)
 
294

Total Assets
 
759

 
33

 
3

 
795

 
(323
)
 
472

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
329

 
23

 
1

 
353

 
(261
)
 
92

Long-term Risk Management Liabilities
 
208

 
8

 
9

 
225

 
(94
)
 
131

Total Liabilities
 
537

 
31

 
10

 
578

 
(355
)
 
223

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
222

 
$
2

 
$
(7
)
 
$
217

 
$
32

 
$
249


(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."
(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.


82



The table below presents our activity of derivative risk management contracts for the three and nine months ended September 30, 2015 and 2014:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three and Nine Months Ended September 30, 2015 and 2014
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Location of Gain (Loss)
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Vertically Integrated Utilities Revenues
 
$

 
$
7

 
$
7

 
$
29

Transmission and Distribution Utilities Revenues
 
(1
)
 

 
(1
)
 

Generation & Marketing Revenues
 
1

 
21

 
60

 
69

Other Operation Expense
 

 

 
(1
)
 

Maintenance Expense
 
(1
)
 

 
(2
)
 

Purchased Electricity for Resale
 
1

 

 
4

 

Regulatory Assets (a)
 

 
(6
)
 

 
(6
)
Regulatory Liabilities (a)
 
(20
)
 
(7
)
 
33

 
111

Total Gain (Loss) on Risk Management Contracts
 
$
(20
)
 
$
15

 
$
100

 
$
203


(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. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. 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.


83



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. The following table shows the results of our hedging gains (losses) during the three and nine months ended September 30, 2015 and 2014:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Gain (Loss) on Fair Value Hedging Instruments
$
4

 
$
(2
)
 
$
7

 
$
2

Gain (Loss) on Fair Value Portion of Long-term Debt
(4
)
 
2

 
(7
)
 
(2
)

During the three and nine months ended September 30, 2015 and 2014, hedge ineffectiveness was immaterial.

Accounting for Cash Flow Hedging Strategies

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

Realized gains and losses on derivative contracts for the purchase and sale of power and natural gas designated as cash flow hedges are included in Revenues 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, 2015 and 2014, we designated power derivatives as cash flow hedges but did not designate 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. The impact of cash flow hedge accounting for these derivative contracts was immaterial and discontinued 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, 2015 and 2014, 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, 2015 and 2014, we did not designate any foreign currency derivatives as cash flow hedges. 

During the three and nine months ended September 30, 2015 and 2014, 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, 2015 and 2014, see Note 3.


84



Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2015 and December 31, 2014 were:
Impact of Cash Flow Hedges on the Condensed Balance Sheet
September 30, 2015
 
 
 
 
 
 
 
Commodity
 
Interest Rate
and Foreign
Currency
 
Total
 
(in millions)
Hedging Assets (a)
$
7

 
$

 
$
7

Hedging Liabilities (a)
24

 
1

 
25

AOCI Loss Net of Tax
(11
)
 
(18
)
 
(29
)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months
1

 
(1
)
 

 
 
 
 
 
 
Impact of Cash Flow Hedges on the Condensed Balance Sheet
December 31, 2014
 
 
 
 
 
 
 
Commodity
 
Interest Rate
and Foreign
Currency
 
Total
 
(in millions)
Hedging Assets (a)
$
16

 
$

 
$
16

Hedging Liabilities (a)
14

 
1

 
15

AOCI Gain (Loss) Net of Tax
1

 
(19
)
 
(18
)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months
4

 
(2
)
 
2


(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, 2015, 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 87 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.


85



Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs), we are obligated to post an additional amount of collateral for a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads and guaranties for contractual obligations 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 our exposure if our credit ratings were to decline below a specified rating threshold as of September 30, 2015 and December 31, 2014:
 
 
September 30,
 
December 31,
 
 
2015
 
2014
 
 
(in millions)
Fair Value of Contracts with Credit Downgrade Triggers
 
$

 
$

Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement
 

 

Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs
 
35

 
36

Amount of Collateral Attributable to Other Contracts (a)
 
299

 
281


(a)
Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contracts.

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, 2015 and December 31, 2014:
 
September 30,
2015
 
December 31,
2014
 
(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements
$
307

 
$
235

Amount of Cash Collateral Posted
10

 
9

Additional Settlement Liability if Cross Default Provision is Triggered
251

 
178



86


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 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 inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and

87


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, 2015 and December 31, 2014 are summarized in the following table:
 
September 30, 2015
 
December 31, 2014
 
Book Value (a)
 
Fair Value
 
Book Value (a)
 
Fair Value
 
(in millions)
Long-term Debt
$
19,507

 
$
21,257

 
$
18,684

 
$
21,075


(a)
Amounts include debt related to AEPRO that have been classified as Liabilities Held for Sale on the condensed balance sheets. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information.

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, 2015
Other Temporary Investments
 
Cost
 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
 
(in millions)
Restricted Cash (a)
 
$
201

 
$

 
$

 
$
201

Fixed Income Securities  Mutual Funds
 
90

 

 

 
90

Equity Securities  Mutual Funds
 
14

 
10

 

 
24

Total Other Temporary Investments
 
$
305

 
$
10

 
$

 
$
315

 
 
 
 
 
 
 
 
 
 
 
December 31, 2014
Other Temporary Investments
 
Cost
 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
 
(in millions)
Restricted Cash (a)
 
$
280

 
$

 
$

 
$
280

Fixed Income Securities  Mutual Funds
 
81

 

 

 
81

Equity Securities  Mutual Funds
 
13

 
12

 

 
25

Total Other Temporary Investments
 
$
374

 
$
12

 
$

 
$
386


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

88


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, 2015 and 2014:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Proceeds from Investment Sales
$

 
$

 
$

 
$

Purchases of Investments
10

 

 
10

 
1

Gross Realized Gains on Investment Sales

 

 

 

Gross Realized Losses on Investment Sales

 

 

 


As of September 30, 2015 and December 31, 2014, we had no Other Temporary Investments with an unrealized loss position.  As of September 30, 2015, 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, 2015 and 2014, 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.


89


The following is a summary of nuclear trust fund investments as of September 30, 2015 and December 31, 2014:
 
September 30, 2015
 
December 31, 2014
 
Fair
Value
 
Gross
Unrealized
Gains
 
Other-Than-
Temporary
Impairments
 
Fair
Value
 
Gross
Unrealized
Gains
 
Other-Than-
Temporary
Impairments
 
(in millions)
Cash and Cash Equivalents
$
164

 
$

 
$

 
$
20

 
$

 
$

Fixed Income Securities:
 

 
 

 
 

 
 
 
 

 
 

United States Government
704

 
45

 
(2
)
 
697

 
45

 
(5
)
Corporate Debt
62

 
4

 
(1
)
 
48

 
4

 
(1
)
State and Local Government
50

 
1

 

 
208

 
1

 

Subtotal Fixed Income Securities
816

 
50

 
(3
)
 
953

 
50

 
(6
)
Equity Securities  Domestic
1,067

 
516

 
(80
)
 
1,123

 
599

 
(79
)
Spent Nuclear Fuel and Decommissioning Trusts
$
2,047

 
$
566

 
$
(83
)
 
$
2,096

 
$
649

 
$
(85
)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2015 and 2014:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Proceeds from Investment Sales
$
921

 
$
263

 
$
1,437

 
$
746

Purchases of Investments
938

 
281

 
1,479

 
790

Gross Realized Gains on Investment Sales
15

 
8

 
34

 
25

Gross Realized Losses on Investment Sales
13

 
1

 
23

 
10


The adjusted cost of fixed income securities was $766 million and $903 million as of September 30, 2015 and December 31, 2014, respectively.  The adjusted cost of equity securities was $551 million and $524 million as of September 30, 2015 and December 31, 2014, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2015 was as follows:
 
Fair Value of
Fixed Income
Securities
 
(in millions)
Within 1 year
$
166

1 year – 5 years
336

5 years – 10 years
140

After 10 years
174

Total
$
816



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Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014.  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, 2015
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
$
12

 
$
4

 
$

 
$
162

 
$
178

 
 
 
 
 
 
 
 
 
 
 
Other Temporary Investments
 
 
 
 
 
 
 
 
 
 
Restricted Cash (a)
 
189

 
6

 

 
6

 
201

Fixed Income Securities - Mutual Funds
 
90

 

 

 

 
90

Equity Securities  Mutual Funds (b)
 
24

 

 

 

 
24

Total Other Temporary Investments
 
303

 
6

 

 
6

 
315

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (c) (d)
 
17

 
478

 
248

 
(256
)
 
487

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (c)
 

 
10

 
1

 
(4
)
 
7

Fair Value Hedges
 

 
1

 

 
1

 
2

Total Risk Management Assets
 
17

 
489

 
249

 
(259
)
 
496

 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 

 
 

 
 

 
 

 
 

Cash and Cash Equivalents (e)
 
157

 

 

 
7

 
164

Fixed Income Securities:
 
 

 
 

 
 

 
 

 
 

United States Government
 

 
704

 

 

 
704

Corporate Debt
 

 
62

 

 

 
62

State and Local Government
 

 
50

 

 

 
50

Subtotal Fixed Income Securities
 

 
816

 

 

 
816

Equity Securities  Domestic (b)
 
1,067

 

 

 

 
1,067

Total Spent Nuclear Fuel and Decommissioning Trusts
 
1,224

 
816

 

 
7

 
2,047

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
1,556

 
$
1,315

 
$
249

 
$
(84
)
 
$
3,036

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (c) (d)
 
$
33

 
$
440

 
$
76

 
$
(299
)
 
$
250

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (c)
 

 
22

 
6

 
(4
)
 
24

Interest Rate/Foreign Currency Hedges
 

 
1

 

 

 
1

Fair Value Hedges
 

 

 

 
1

 
1

Total Risk Management Liabilities
 
$
33

 
$
463

 
$
82

 
$
(302
)
 
$
276



91


Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2014
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
$
17

 
$
1

 
$

 
$
145

 
$
163

 
 
 
 
 
 
 
 
 
 
 
Other Temporary Investments
 
 
 
 
 
 
 
 
 
 
Restricted Cash (a)
 
234

 
9

 

 
37

 
280

Fixed Income Securities - Mutual Funds
 
81

 

 

 

 
81

Equity Securities  Mutual Funds (b)
 
25

 

 

 

 
25

Total Other Temporary Investments
 
340

 
9

 

 
37

 
386

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (c) (f)
 
37

 
528

 
190

 
(302
)
 
453

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (c)
 

 
32

 

 
(16
)
 
16

Fair Value Hedges
 

 
1

 

 
2

 
3

Total Risk Management Assets
 
37

 
561

 
190

 
(316
)
 
472

 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 

 
 

 
 

 
 

 
 

Cash and Cash Equivalents (e)
 
9

 

 

 
11

 
20

Fixed Income Securities:
 
 

 
 

 
 

 
 

 
 

United States Government
 

 
697

 

 

 
697

Corporate Debt
 

 
48

 

 

 
48

State and Local Government
 

 
208

 

 

 
208

Subtotal Fixed Income Securities
 

 
953

 

 

 
953

Equity Securities  Domestic (b)
 
1,123

 

 

 

 
1,123

Total Spent Nuclear Fuel and Decommissioning Trusts
 
1,132

 
953

 

 
11

 
2,096

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
1,526

 
$
1,524

 
$
190

 
$
(123
)
 
$
3,117

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (c) (f)
 
$
65

 
$
432

 
$
36

 
$
(334
)
 
$
199

Cash Flow Hedges:
 
 

 
 

 
 

 
 

 
 

Commodity Hedges (c)
 

 
27

 
3

 
(16
)
 
14

Interest Rate/Foreign Currency Hedges
 

 
1

 

 

 
1

Fair Value Hedges
 

 
7

 

 
2

 
9

Total Risk Management Liabilities
 
$
65

 
$
467

 
$
39

 
$
(348
)
 
$
223


(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, 2015 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 2015 and ($12) million in periods 2016-2018;  Level 2 matures $5 million in 2015, $28 million in periods 2016-2018, $3 million in periods 2019-2020 and $2 million in periods 2021-2032;  Level 3 matures $2 million in 2015, $63 million in periods 2016-2018, $25 million in periods 2019-2020 and $82 million in periods 2021-2032.  Risk management commodity contracts are substantially comprised of power contracts.
(e)
Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(f)
The December 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $(18) million in 2015 and ($10) million in periods 2016-2018;  Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030;  Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030.  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, 2015 and 2014.


92


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, 2015
 
Net Risk Management
Assets (Liabilities)
 
 
(in millions)
Balance as of June 30, 2015
 
$
203

Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
11

Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
 
6

Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
(2
)
Purchases, Issuances and Settlements (c)
 
(29
)
Transfers into Level 3 (d) (e)
 
8

Transfers out of Level 3 (e) (f)
 
(5
)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
(25
)
Balance as of September 30, 2015
 
$
167

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

Nine Months Ended September 30, 2015
 
Net Risk Management
Assets (Liabilities)
 
 
(in millions)
Balance as of December 31, 2014
 
$
151

Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
14

Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
 
54

Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
(4
)
Purchases, Issuances and Settlements (c)
 
(60
)
Transfers into Level 3 (d) (e)
 
28

Transfers out of Level 3 (e) (f)
 
(17
)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
1

Balance as of September 30, 2015
 
$
167


93


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


(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.


94


The following tables quantify the significant unobservable inputs used in developing the fair value of our Level 3 positions as of September 30, 2015 and December 31, 2014:

Significant Unobservable Inputs
September 30, 2015
 
 
 
 
 
Significant
 
Input/Range
 
Fair Value
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
Technique
 
Input
 
Low
 
High
 
Average
 
(in millions)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
$
226

 
$
79

 
Discounted Cash Flow 
 
Forward Market Price (a) 
 
$
13.03

 
$
165.93

 
$
36.37

 
 
 
 
 
 
 
Counterparty Credit Risk (b) 
 
481
FTRs
23

 
3

 
Discounted Cash Flow 
 
Forward Market Price (a) 
 
(10.67
)
 
11.60

 
1.31

Total
$
249

 
$
82

 
 
 
 
 
 

 
 

 
 

Significant Unobservable Inputs
December 31, 2014
 
 
 
 
 
Significant
 
Input/Range
 
Fair Value
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
Technique
 
Input
 
Low
 
High
 
Average
 
(in millions)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
$
157

 
$
37

 
Discounted Cash Flow 
 
Forward Market Price (a) 
 
$
11.37

 
$
159.92

 
$
57.18

 
 
 
 
 
 
 
Counterparty Credit Risk (b) 
 
303
FTRs
33

 
2

 
Discounted Cash Flow 
 
Forward Market Price (a) 
 
(14.63
)
 
20.02

 
0.96

Total
$
190

 
$
39

 
 
 
 
 
 

 
 

 
 

(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, 2015:

Sensitivity of Fair Value Measurements
September 30, 2015
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)



95



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.

Valuation Allowance

We assess the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to use existing deferred tax assets.  On the basis of this evaluation, we recorded a valuation allowance of $165 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of our investment in the operations of AEPRO.  The assets and liabilities of AEPRO have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on our condensed balance sheets as of September 30, 2015 and December 31, 2014.  See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information regarding the assets and liabilities classified as held for sale.  As of September 30, 2015, valuation allowances totaling $221 million for unrealized capital losses have been recorded in order to recognize only the portion of the deferred tax assets that, more likely than not, will be realized. 

Federal and State Income Tax Audit Status

We are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 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.

State Tax Legislation

House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact net income, cash flows or financial condition.



96



12.  FINANCING ACTIVITIES

Long-term Debt

The following table details long-term debt outstanding as of September 30, 2015 and December 31, 2014:
Type of Debt
 
September 30, 2015
 
December 31, 2014
 
 
(in millions)
Senior Unsecured Notes
 
$
13,801

 
$
12,647

Pollution Control Bonds
 
1,874

 
1,963

Notes Payable (a)
 
374

 
357

Securitization Bonds
 
2,072

 
2,380

Spent Nuclear Fuel Obligation (b)
 
266

 
266

Other Long-term Debt
 
1,151

 
1,101

Fair Value of Interest Rate Hedges
 

 
(6
)
Unamortized Discount, Net
 
(31
)
 
(24
)
Total Long-term Debt Outstanding (a)
 
19,507

 
18,684

Long-term Debt Due Within One Year (a)
 
1,907

 
2,503

Long-term Debt (a)
 
$
17,600

 
$
16,181


(a)
Amounts include debt related to AEPRO that have been classified as Liabilities Held for Sale on the condensed balance sheets. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information.
(b)
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, 2015 and December 31, 2014, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the condensed balance sheets.


97



Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2015 are shown in the tables below:
Company
 
Type of Debt
 
Principal
Amount
 
Interest
Rate
 
Due Date
Issuances:
 
 
 
(in millions)
 
(%)
 
 
APCo
 
Pollution Control Bonds
 
$
86

 
1.90
 
2019
APCo
 
Senior Unsecured Notes
 
350

 
4.45
 
2045
APCo
 
Senior Unsecured Notes
 
300

 
3.40
 
2025
I&M
 
Notes Payable
 
111

 
Variable
 
2019
I&M
 
Other Long-term Debt
 
100

 
Variable
 
2018
PSO
 
Senior Unsecured Notes
 
125

 
3.17
 
2025
PSO
 
Senior Unsecured Notes
 
125

 
4.09
 
2045
SWEPCo
 
Pollution Control Bonds
 
54

 
1.60
 
2019
SWEPCo
 
Senior Unsecured Notes
 
400

 
3.90
 
2045
 
 
 
 
 
 
 
 
 
Non-Registrant:
 
 
 
 

 
 
 
 
AEPTCo
 
Senior Unsecured Notes
 
60

 
4.01
 
2030
AEPTCo
 
Senior Unsecured Notes
 
50

 
3.66
 
2025
AEPTCo
 
Senior Unsecured Notes
 
40

 
3.76
 
2025
AGR
 
Other Long-term Debt
 
500

 
Variable
 
2017
KPCo
 
Other Long-term Debt
 
25

 
Variable
 
2018
TCC
 
Senior Unsecured Notes
 
250

 
3.85
 
2025
TNC
 
Senior Unsecured Notes
 
50

 
3.75
 
2025
TNC
 
Senior Unsecured Notes
 
25

 
3.27
 
2022
Transource Missouri
 
Other Long-term Debt
 
20

 
Variable
 
2018
WPCo
 
Senior Unsecured Notes
 
113

 
3.36
 
2022
WPCo
 
Senior Unsecured Notes
 
122

 
3.70
 
2025
WPCo
 
Senior Unsecured Notes
 
50

 
4.20
 
2035
Total Issuances
 
 
 
$
2,956

(a)
 
 
 

(a)
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.

98



Company
 
Type of Debt
 
Principal
Amount Paid
 
Interest
Rate
 
Due Date
Total Retirements and Principal Payments:
 
 
 
(in millions)
 
(%)
 
 
APCo
 
Securitization Bonds
 
$
23

 
2.008
 
2024
APCo
 
Senior Unsecured Notes
 
350

 
7.95
 
2020
APCo
 
Senior Unsecured Notes
 
300

 
3.40
 
2015
I&M
 
Other Long-term Debt
 
94

 
Variable
 
2015
I&M
 
Other Long-term Debt
 
1

 
6.00
 
2025
I&M
 
Notes Payable
 
18

 
Variable
 
2016
I&M
 
Notes Payable
 
21

 
Variable
 
2017
I&M
 
Notes Payable
 
26

 
Variable
 
2019
I&M
 
Notes Payable
 
16

 
Variable
 
2019
I&M
 
Notes Payable
 
1

 
Variable
 
2016
I&M
 
Notes Payable
 
1

 
2.12
 
2016
OPCo
 
Pollution Control Bonds
 
86

 
3.125
 
2015
OPCo
 
Securitization Bonds
 
45

 
0.958
 
2018
SWEPCo
 
Notes Payable
 
3

 
4.58
 
2032
SWEPCo
 
Pollution Control Bonds
 
54

 
3.25
 
2015
SWEPCo
 
Senior Unsecured Notes
 
100

 
5.375
 
2015
SWEPCo
 
Senior Unsecured Notes
 
150

 
4.90
 
2015
 
 
 
 
 
 
 
 
 
Non-Registrant:
 
 
 
 

 
 
 
 
AEGCo
 
Senior Unsecured Notes
 
7

 
6.33
 
2037
AEP Subsidiaries
 
Notes Payable
 
5

 
Variable
 
2017
AEP Subsidiaries
 
Notes Payable
 
1

(a)
7.59
 
2026
AEP Subsidiaries
 
Notes Payable
 
1

(a)
8.03
 
2026
AGR
 
Other Long-term Debt
 
500

 
Variable
 
2015
AGR
 
Pollution Control Bonds
 
50

 
Variable
 
2015
AGR
 
Pollution Control Bonds
 
39

 
Variable
 
2015
TCC
 
Securitization Bonds
 
81

 
5.09
 
2015
TCC
 
Securitization Bonds
 
76

 
6.25
 
2016
TCC
 
Securitization Bonds
 
27

 
0.88
 
2017
TCC
 
Securitization Bonds
 
57

 
5.17
 
2018
Total Retirements and Principal Payments
 
 
 
$
2,133

(a)
 
 
 

(a)
Amount includes principal payments of debt related to AEPRO that has been classified as Discontinued Operations on the condensed statement of cash flows.

In October 2015, KPCo drew the remaining $25 million on an existing $75 million variable rate credit facility due in 2018.

In October 2015, Transource Missouri drew $6 million on an existing $300 million variable rate credit facility due in 2018.

As of September 30, 2015, trustees held on our behalf, $475 million of our reacquired Pollution Control Bonds.


99



Dividend Restrictions

Parent Restrictions

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

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

Utility Subsidiaries’ Restrictions

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

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

Short-term Debt

Our outstanding short-term debt was as follows:
 
 
September 30, 2015
 
December 31, 2014
Type of Debt
 
Outstanding
Amount
 
Interest
Rate (a)
 
Outstanding
Amount
 
Interest
Rate (a)
 
 
(in millions)
 
 

 
(in millions)
 
 

Securitized Debt for Receivables (b)
 
$
750

 
0.28
%
 
$
744

 
0.22
%
Commercial Paper
 
32

 
0.44
%
 
602

 
0.59
%
Total Short-term Debt
 
$
782

 
 

 
$
1,346

 
 


(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.


100



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 2017.

Accounts receivable information for AEP Credit is as follows:
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(dollars in millions)
 
 

 
 

 
 

 
 

Effective Interest Rates on Securitization of Accounts Receivable
0.30
%
 
0.21
%
 
0.28
%
 
0.22
%
Net Uncollectible Accounts Receivable Written Off
$
13

 
$
16

 
$
27

 
$
32

 
September 30, 2015
 
December 31, 2014
 
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts
$
970

 
$
975

Total Principal Outstanding
750

 
744

Delinquent Securitized Accounts Receivable
50

 
44

Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable
16

 
13

Unbilled Receivables Related to Securitization/Sale of Accounts Receivable
277

 
335


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.


101



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, 2015 and 2014 were $41 million and $41 million, respectively, and for the nine months ended September 30, 2015 and 2014 were $124 million and $121 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, which 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 DCC Fuel 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, 2015 and 2014 were $29 million and $28 million, respectively, and for the nine months ended September 30, 2015 and 2014 were $86 million and $84 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months.  Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel’s assets and liabilities on the condensed balance sheets.

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.


102



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 $1.5 billion and $1.8 billion as of September 30, 2015 and December 31, 2014, respectively.  Transition Funding has securitized transition assets of $1.4 billion and $1.6 billion as of September 30, 2015 and December 31, 2014, 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 $187 million and $232 million as of September 30, 2015 and December 31, 2014, respectively.  Ohio Phase-in-Recovery Funding has securitized assets of $92 million and $110 million as of September 30, 2015 and December 31, 2014, 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 $345 million and $368 million as of September 30, 2015 and December 31, 2014, respectively.  Appalachian Consumer Rate Relief Funding has securitized assets of $333 million and $350 million as of September 30, 2015 and December 31, 2014, 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 Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated 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.


103



Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance.  EIS has multiple protected cells.  Neither AEP nor its subsidiaries have an equity investment in EIS.  The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance.  Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims.  Based on our control and the structure of the protected cell of EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate the protected cell of EIS.  Our insurance premium expense to the protected cell for the three months ended September 30, 2015 and 2014 was $13 million and $16 million, respectively, and for the nine months ended September 30, 2015 and 2014 was $27 million and $33 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 (a wholly-owned subsidiary of Transource Energy) 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, construction projects, debt issuance and capital contribution. AEP provided capital contributions to Transource Energy of $32 million and $23 million during the nine months ended September 30, 2015 and the year ended December 31, 2014, respectively. AEP and the other owner of Transource Energy are required to ensure a specific equity level in Transource Missouri upon completion of projects or if a project is abandoned by the RTO. 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, 2015
(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
 
$
61

 
$
104

 
$
977

 
$
197

 
$
20

 
 
$
11

 
$
163

 
$
12

Net Property, Plant and Equipment
 
144

 
193

 

 

 

 
 

 

 
184

Other Noncurrent Assets
 
60

 
101

 
1

 
1,454

(a) 
175

(b) 
 
341

(c)
3

 
5

Total Assets
 
$
265

 
$
398

 
$
978

 
$
1,651

 
$
195

 
 
$
352

 
$
166

 
$
201

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 

 
 
Current Liabilities
 
$
40

 
$
98

 
$
875

 
$
283

 
$
47

 
 
$
25

 
$
49

 
$
47

Noncurrent Liabilities
 
225

 
300

 
1

 
1,350

 
147

 
 
325

 
76

 
80

Equity
 

 

 
102

 
18

 
1

 
 
2

 
41

 
74

Total Liabilities and Equity
 
$
265

 
$
398

 
$
978

 
$
1,651

 
$
195

 
 
$
352

 
$
166

 
$
201


(a)
Includes an intercompany item eliminated in consolidation of $70 million.
(b)
Includes an intercompany item eliminated in consolidation of $81 million.
(c)
Includes an intercompany item eliminated in consolidation of $4 million.

104



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 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
 
$
68

 
$
97

 
$
980

 
$
239

 
$
33

 
 
$
18

 
$
149

 
$
2

Net Property, Plant and Equipment
 
145

 
158

 

 

 

 
 

 

 
98

Other Noncurrent Assets
 
52

 
80

 

 
1,654

(a) 
210

(b) 
 
358

(c)
2

 
4

Total Assets
 
$
265

 
$
335

 
$
980

 
$
1,893

 
$
243

 
 
$
376

 
$
151

 
$
104

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 

 
 
Current Liabilities
 
$
36

 
$
86

 
$
894

 
$
322

 
$
47

 
 
$
27

 
$
44

 
$
21

Noncurrent Liabilities
 
228

 
249

 

 
1,553

 
195

 
 
347

 
62

 
55

Equity
 
1

 

 
86

 
18

 
1

 
 
2

 
45

 
28

Total Liabilities and Equity
 
$
265

 
$
335

 
$
980

 
$
1,893

 
$
243

 
 
$
376

 
$
151

 
$
104


(a)
Includes an intercompany item eliminated in consolidation of $75 million.
(b)
Includes an intercompany item eliminated in consolidation of $97 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, 2015 and 2014 were $30 million and $24 million, respectively, and for the nine months ended September 30, 2015 and 2014 were $59 million and $31 million, respectively.  We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC.  Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets.

Our investment in DHLC was:
 
September 30, 2015
 
December 31, 2014
 
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
6

 
6

 
4

 
4

Advance Due to Parent
40

 
40

 
56

 
56

Guarantee of Debt

 
55

 

 
48

 
 
 
 
 
 
 
 
Total Investment in DHLC
$
54

 
$
109

 
$
68

 
$
116


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 and controlled by a subsidiary of FirstEnergy.  Provisions exist within the PATH-WV agreement that make it 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.

105



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. Hearings at FERC were held in March and April 2015. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, with recommendations on various issues in the case.  The Initial Decision has no binding effect.  Additional briefing is scheduled during the fourth quarter of 2015, after which the case will be pending before FERC.

Our investment in PATH-WV was:
 
September 30, 2015
 
December 31, 2014
 
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
2

 
2

 
2

 
2

 
 
 
 
 
 
 
 
Total Investment in PATH-WV
$
21

 
$
21

 
$
21

 
$
21


As of September 30, 2015, our $21 million investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheet. We believe the financial statements adequately address the impact of the Initial Decision. If we cannot ultimately recover our investment related to PATH-WV, it could reduce future net income and cash flows.

106



14. PROPERTY, PLANT AND EQUIPMENT

Asset Retirement Obligations (ARO)

We record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for our legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities, as well as for nuclear decommissioning of our Cook Plant.  We have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which we have assets.  Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property’s use.  We do not estimate the retirement for such easements because we plan to use our facilities indefinitely.  The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements, which is not expected.

We recorded an increase in our asset retirement obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants.  The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the aggregate carrying amount of ARO, including a $95 million second quarter increase and other adjustments recorded in the third quarter:
 
Carrying
Amount
of ARO
 
(in millions)
ARO as of December 31, 2014
$
2,019

Accretion Expense
76

Liabilities Incurred
48

Liabilities Settled (a)
(126
)
Revisions in Cash Flow Estimates (b)
30

ARO as of September 30, 2015
$
2,047


(a)
Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the "Muskingum River Plant" section of Note 6.
(b)
Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party.

As of September 30, 2015 and December 31, 2014, our ARO liability included $1.31 billion and $1.27 billion, respectively, for nuclear decommissioning of the Cook Plant.  As of September 30, 2015 and December 31, 2014, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $1.74 billion and $1.79 billion, respectively, and are recorded in Spent Nuclear Fuel and Decommissioning Trusts on the condensed balance sheets.


107



15.  DISPOSITION PLANT SEVERANCE

AEP retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits.

The disposition plant severance activity for the nine months ended September 30, 2015 is described in the following table:
 
 
Disposition Plant
Severance Activity
 
 
(in millions)
Balance as of December 31, 2014
 
$
29

Incurred
 
3

Settled
 
(21
)
Adjustments
 

Balance as of September 30, 2015
 
$
11


We recorded a charge of $29 million to Other Operation expense in 2014 primarily related to employees at the disposition plants. These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income.  Of the cumulative expense, approximately 32% was within the Generation & Marketing segment and 68% was within the Vertically Integrated Utilities segment.  The remaining liability is included in Other Current Liabilities on the condensed balance sheets. We incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. We do not expect additional severance costs to be incurred related to this initiative.


108





APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

109




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

EXECUTIVE OVERVIEW

Regulatory Activity

2015 Virginia Regulatory Asset Proceeding

In January 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets. In February and March 2015, briefs related to this proceeding were filed by various parties. As of September 30, 2015, APCo’s authorized regulatory assets under review in this proceeding were $11 million. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition.

New Virginia Legislation Affecting Biennial Reviews

In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA.

West Virginia Inquiry into Plant Closures

Subsequent to APCo’s retirement of the Kanawha River Plant in May 2015, the WVPSC issued an order in July 2015 that requested APCo to maintain, for at least four years, any infrastructure installed at the Kanawha River Plant that would be used if the plant were to be converted to burn natural gas. The WVPSC stated that it would not be reasonable and prudent to completely demolish facilities that might be available in the future for conversion to natural gas before further consideration is given to the future of APCo’s coal fired generation. The order indicated that the WVPSC would consider prudently incurred operating fees related to Kanawha River and Sporn Plants for recovery in a future case. In October 2015, APCo filed an application with the WVPSC to request that it be relieved of any obligation to study further the future viability of the Sporn Plant and Glen Lyn Plant units and of any obligation to maintain these units.  Additionally, APCo plans to consider the Kanawha River Plant units in its preparation of an integrated resource plan to be filed with the WVPSC by December 31, 2015.

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 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in the 2014 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 179. 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 256 for additional discussion of relevant factors.

110



RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions of KWhs)
Retail:
 

 
 

 
 

 
 

Residential
2,599

 
2,503

 
9,039

 
9,131

Commercial
1,744

 
1,726

 
5,161

 
5,150

Industrial
2,493

 
2,600

 
7,520

 
7,665

Miscellaneous
205

 
205

 
633

 
636

Total Retail
7,041

 
7,034

 
22,353

 
22,582

 
 
 
 
 
 
 
 
Wholesale
681

 
563

 
2,335

 
2,507

 
 
 
 
 
 
 
 
Total KWhs
7,722

 
7,597

 
24,688

 
25,089


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,
 
2015
 
2014
 
2015
 
2014
 
(in degree days)
Actual - Heating (a)

 

 
1,735

 
1,776

Normal - Heating (b)
3

 
2

 
1,415

 
1,405

 
 
 
 
 
 
 
 
Actual - Cooling (c)
804

 
639

 
1,275

 
1,041

Normal - Cooling (b)
809

 
816

 
1,175

 
1,183


(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.


111



Third Quarter of 2015 Compared to Third Quarter of 2014
Reconciliation of Third Quarter of 2014 to Third Quarter of 2015
Net Income
(in millions)
 
Third Quarter of 2014
 
$
49

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
35

Off-system Sales
 
(1
)
Transmission Revenues
 
(8
)
Other Revenues
 
2

Total Change in Gross Margin
 
28

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(4
)
Depreciation and Amortization
 
4

Allowance for Equity Funds Used During Construction
 
1

Interest Expense
 
6

Total Change in Expenses and Other
 
7

 
 
 

Income Tax Expense
 
(9
)
 
 
 

Third Quarter of 2015
 
$
75


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

Retail Margins increased $35 million primarily due to the following:
A $32 million increase primarily due to increases in rates in West Virginia, offset by decreases in rates in Virginia and formula rates in both jurisdictions.  Of these changes, $4 million relates to riders/trackers which have corresponding increases in other expense items below.
A $14 million increase in weather-related usage primarily due to a 26% increase in cooling degree days.
These increases were partially offset by:
A $12 million decrease in weather-normalized margin primarily due to lower industrial usage.
Transmission Revenues decreased $8 million primarily due to lower Network Integrated Transmission Service (NITS) revenues.  These NITS revenues are partially offset in Other Operation and Maintenance expenses below.


112



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

Other Operation and Maintenance expenses increased $4 million primarily due to the following:
A $14 million increase in distribution expenses primarily related to implementation of a surcharge to recover West Virginia vegetation management expenses effective June 2015 and increased amortization of West Virginia storm costs.
A $3 million increase in generation operation expenses primarily related to amortizations of West Virginia Carbon Capture storage and IGCC and decommissioning expenses at disposition plants.  This increase was partially offset in Gross Margin above.
A $2 million increase in customer accounts expenses related to customer assistance and uncollectible accounts.
These increases were partially offset by:
A $7 million decrease in steam and electric plant maintenance expenses primarily at the Amos and Mountaineer Plants.
A $6 million decrease associated with the under recovery of transmission costs in accordance with the Virginia Transmission Rate Adjustment Clause as allowed by the Virginia SCC.
A $2 million decrease in PJM expenses primarily related to NITS.  This decrease is partially offset by a corresponding decrease in Gross Margin above.
Depreciation and Amortization expenses decreased $4 million due to prior year amortization of Virginia environmental deferrals, which ended in the first quarter of 2015.
Interest Expense decreased $6 million primarily due to the following:
A $4 million decrease due to lower interest rates on long-term debt.
Income Tax Expense increased $9 million primarily due to an increase in pretax book income, partially offset by the recording of federal and state income tax adjustments.

113



Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015
Net Income
(in millions)
 
Nine Months Ended September 30, 2014
 
$
187

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
116

Off-system Sales
 
(3
)
Transmission Revenues
 
(6
)
Other Revenues
 
2

Total Change in Gross Margin
 
109

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 

Depreciation and Amortization
 
7

Taxes Other Than Income Taxes
 
(1
)
Carrying Costs Income
 
2

Allowance for Equity Funds Used During Construction
 
6

Interest Expense
 
12

Total Change in Expenses and Other
 
26

 
 
 

Income Tax Expense
 
(47
)
 
 
 

Nine Months Ended September 30, 2015
 
$
275


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

Retail Margins increased $116 million primarily due to the following:
A $93 million increase primarily due to increases in rates in West Virginia and Virginia, as well as an adjustment due to the amended Virginia law impacting biennial reviews.  Of these increases, $13 million relate to riders/trackers which have corresponding increases in other expense items below.
An $18 million increase in weather-related usage primarily due to a 23% increase in cooling degree days.
A $10 million decrease in generation related PJM expenses due to the polar vortex in 2014 net of recovery or offsets.
A $7 million decrease in fuel expense from wholesale customers due to the timing of fuel recovery in 2014.
A $3 million decrease in consumables and allowances expense.
These increases were partially offset by:
A $32 million decrease in weather-normalized margin primarily due to lower usage.
Transmission Revenues decreased $6 million primarily due to lower NITS revenues. 


114



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

Other Operation and Maintenance expenses were approximately unchanged primarily due to the following:
A $21 million increase in PJM expenses primarily related to NITS.  
This increase was partially offset by:
A $21 million decrease in plant maintenance expenses primarily at Amos Plant.
Depreciation and Amortization expenses decreased $7 million primarily due to the following:
A $9 million decrease due to prior year amortization of Virginia environmental deferrals, which ended in the first quarter of 2015.
A $2 million decrease due to prior year amortization of West Virginia ENEC deferrals.
These decreases were partially offset by:
A $4 million increase due to a higher depreciable base.
Carrying Cost Income increased $2 million related to West Virginia ENEC deferrals.
Allowance for Equity Funds Used During Construction increased $6 million primarily due to increased transmission projects.
Interest Expense decreased $12 million primarily due to the following:
A $5 million decrease due to lower interest rates on long-term debt.
A $3 million decrease due to higher debt component of AFUDC from increased transmission projects.
A $2 million decrease due to a 2014 amortization of loss on reacquired long-term debt.
Income Tax Expense increased $47 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 2014 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 256 for a discussion of accounting pronouncements.


115




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
REVENUES
 
 
 
 
 
 
 
 

Electric Generation, Transmission and Distribution
 
$
685,312

 
$
672,459

 
$
2,184,943

 
$
2,202,967

Sales to AEP Affiliates
 
39,389

 
35,455

 
115,740

 
108,439

Other Revenues
 
2,857

 
1,970

 
7,870

 
6,537

TOTAL REVENUES
 
727,558

 
709,884

 
2,308,553

 
2,317,943

 
 
 
 
 
 
 
 
 
EXPENSES
 
 

 
 

 
 

 
 

Fuel and Other Consumables Used for Electric Generation
 
188,576

 
194,303

 
595,308

 
627,943

Purchased Electricity for Resale
 
80,452

 
85,656

 
258,836

 
340,680

Purchased Electricity from AEP Affiliates
 

 

 

 
4,662

Other Operation
 
101,841

 
103,835

 
311,631

 
297,269

Maintenance
 
70,459

 
64,333

 
179,793

 
193,907

Depreciation and Amortization
 
96,295

 
99,889

 
292,735

 
300,125

Taxes Other Than Income Taxes
 
32,002

 
31,632

 
93,089

 
92,434

TOTAL EXPENSES
 
569,625

 
579,648

 
1,731,392

 
1,857,020

 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
157,933

 
130,236

 
577,161

 
460,923

 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 

 
 

 
 

 
 

Interest Income
 
290

 
521

 
1,128

 
1,311

Carrying Costs Income (Expense)
 
73

 
482

 
783

 
(1,130
)
Allowance for Equity Funds Used During Construction
 
3,432

 
1,665

 
10,337

 
4,525

Interest Expense
 
(46,625
)
 
(52,738
)
 
(145,600
)
 
(157,540
)
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
115,103

 
80,166

 
443,809

 
308,089

 
 
 
 
 
 
 
 
 
Income Tax Expense
 
40,507

 
31,408

 
168,368

 
121,233

 
 
 
 
 
 
 
 
 
NET INCOME
 
$
74,596

 
$
48,758

 
$
275,441

 
$
186,856

The common stock of APCo is wholly-owned by AEP.
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.



116



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
  Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
Net Income
 
$
74,596

 
$
48,758

 
$
275,441

 
$
186,856

 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
 
 

 
 

 
 

 
 

Cash Flow Hedges, Net of Tax of $120 and $92 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $49 and $314 for the Nine Months Ended September 30, 2015 and 2014, Respectively
 
(222
)
 
170

 
(91
)
 
582

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $247 and $179 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $740 and $538 for the Nine Months Ended September 30, 2015 and 2014, Respectively
 
(458
)
 
(333
)
 
(1,374
)
 
(999
)
 
 
 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE LOSS
 
(680
)
 
(163
)
 
(1,465
)
 
(417
)
 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
$
73,916

 
$
48,595

 
$
273,976

 
$
186,439

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.



117



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
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

 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2014
 
$
260,458

 
$
1,809,562

 
$
1,291,876

 
$
5,032

 
$
3,366,928

 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 

 
 

 
(181,250
)
 
 

 
(181,250
)
Net Income
 
 

 
 

 
275,441

 
 

 
275,441

Other Comprehensive Loss
 
 

 
 

 
 

 
(1,465
)
 
(1,465
)
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2015
 
$
260,458

 
$
1,809,562

 
$
1,386,067

 
$
3,567

 
$
3,459,654

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.




118



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2015 and December 31, 2014
(in thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2015
 
2014
CURRENT ASSETS
 
 
 
 
Cash and Cash Equivalents
 
$
2,411

 
$
2,613

Restricted Cash for Securitized Funding
 
7,436

 
15,599

Advances to Affiliates
 
23,535

 
48,519

Accounts Receivable:
 
 
 
 
Customers
 
118,331

 
114,711

Affiliated Companies
 
56,687

 
67,294

Accrued Unbilled Revenues
 
36,629

 
58,022

Miscellaneous
 
3,180

 
1,956

Allowance for Uncollectible Accounts
 
(3,961
)
 
(2,364
)
Total Accounts Receivable
 
210,866

 
239,619

Fuel
 
77,785

 
113,386

Materials and Supplies
 
126,941

 
131,285

Risk Management Assets – Nonaffiliated
 
25,970

 
23,792

Risk Management Assets – Affiliated
 
1,380

 

Deferred Income Tax Benefits
 

 
23,955

Regulatory Asset for Under-Recovered Fuel Costs
 
69,013

 
66,076

Prepayments and Other Current Assets
 
27,673

 
13,660

TOTAL CURRENT ASSETS
 
573,010

 
678,504

 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
Electric:
 
 
 
 
Generation
 
6,174,000

 
6,824,029

Transmission
 
2,271,351

 
2,228,029

Distribution
 
3,351,264

 
3,258,306

Other Property, Plant and Equipment
 
390,180

 
373,520

Construction Work in Progress
 
535,112

 
321,495

Total Property, Plant and Equipment
 
12,721,907

 
13,005,379

Accumulated Depreciation and Amortization
 
3,426,961

 
3,823,664

TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
9,294,946

 
9,181,715

 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
Regulatory Assets
 
1,061,715

 
857,872

Securitized Assets
 
333,491

 
350,170

Long-term Risk Management Assets – Nonaffiliated
 
2,035

 
4,891

Deferred Charges and Other Noncurrent Assets
 
141,012

 
159,230

TOTAL OTHER NONCURRENT ASSETS
 
1,538,253

 
1,372,163

 
 
 
 
 
TOTAL ASSETS
 
$
11,406,209

 
$
11,232,382

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.



119



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
September 30, 2015 and December 31, 2014
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2015
 
2014
 
 
(in thousands)
CURRENT LIABILITIES
 
 
 
 
Advances from Affiliates
 
$
35,224

 
$

Accounts Payable:
 
 

 
 

General
 
186,317

 
166,821

Affiliated Companies
 
74,006

 
80,602

Long-term Debt Due Within One Year – Nonaffiliated
 
318,020

 
552,212

Long-term Debt Due Within One Year – Affiliated
 

 
86,000

Risk Management Liabilities – Nonaffiliated
 
6,902

 
11,017

Customer Deposits
 
79,237

 
71,766

Accrued Taxes
 
45,938

 
109,482

Accrued Interest
 
63,837

 
52,141

Other Current Liabilities
 
182,191

 
145,017

TOTAL CURRENT LIABILITIES
 
991,672

 
1,275,058

 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
Long-term Debt – Nonaffiliated
 
3,637,275

 
3,342,062

Long-term Risk Management Liabilities – Nonaffiliated
 
973

 
2,057

Deferred Income Taxes
 
2,410,754

 
2,288,842

Regulatory Liabilities and Deferred Investment Tax Credits
 
646,262

 
652,867

Asset Retirement Obligations
 
110,474

 
122,300

Employee Benefits and Pension Obligations
 
119,986

 
127,980

Deferred Credits and Other Noncurrent Liabilities
 
29,159

 
54,288

TOTAL NONCURRENT LIABILITIES
 
6,954,883

 
6,590,396

 
 
 
 
 
TOTAL LIABILITIES
 
7,946,555

 
7,865,454

 
 
 
 
 
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
 
1,386,067

 
1,291,876

Accumulated Other Comprehensive Income (Loss)
 
3,567

 
5,032

TOTAL COMMON SHAREHOLDER’S EQUITY
 
3,459,654

 
3,366,928

 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
11,406,209

 
$
11,232,382

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.


120



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
Nine Months Ended September 30,
 
 
2015
 
2014
OPERATING ACTIVITIES
 
 

 
 

Net Income
 
$
275,441

 
$
186,856

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

 
 

Depreciation and Amortization
 
292,735

 
300,125

Deferred Income Taxes
 
179,143

 
114,778

Carrying Costs Income (Expense)
 
(783
)
 
1,130

Allowance for Equity Funds Used During Construction
 
(10,337
)
 
(4,525
)
Mark-to-Market of Risk Management Contracts
 
(5,902
)
 
255

Pension Contributions to Qualified Plan Trust
 
(9,981
)
 
(8,963
)
Property Taxes
 
27,980

 
25,856

Fuel Over/Under-Recovery, Net
 
(1,729
)
 
(114,022
)
Change in Other Noncurrent Assets
 
(32,481
)
 
(19,178
)
Change in Other Noncurrent Liabilities
 
(27,399
)
 
29,312

Changes in Certain Components of Working Capital:
 
 

 
 

Accounts Receivable, Net
 
28,753

 
114,387

Fuel, Materials and Supplies
 
31,352

 
78,977

Accounts Payable
 
2,678

 
(65,358
)
Accrued Taxes, Net
 
(75,290
)
 
(43,092
)
Other Current Assets
 
(2,628
)
 
(3,748
)
Other Current Liabilities
 
15,411

 
9,085

Net Cash Flows from Operating Activities
 
686,963

 
601,875

 
 
 
 
 
INVESTING ACTIVITIES
 
 

 
 

Construction Expenditures
 
(456,721
)
 
(342,291
)
Change in Advances to Affiliates, Net
 
24,984

 
22,395

Other Investing Activities
 
18,868

 
(1,114
)
Net Cash Flows Used for Investing Activities
 
(412,869
)
 
(321,010
)
 
 
 
 
 
FINANCING ACTIVITIES
 
 

 
 

Issuance of Long-term Debt – Nonaffiliated
 
726,330

 
295,039

Change in Advances from Affiliates, Net
 
35,224

 

Retirement of Long-term Debt – Nonaffiliated
 
(672,552
)
 
(512,702
)
Retirement of Long-term Debt – Affiliated
 
(86,000
)
 

Make Whole Premium on Extinguishment of Long-term Debt  Nonaffiliated
 
(92,658
)


Principal Payments for Capital Lease Obligations
 
(3,843
)
 
(4,255
)
Dividends Paid on Common Stock
 
(181,250
)
 
(60,000
)
Other Financing Activities
 
453

 
1,009

Net Cash Flows Used for Financing Activities
 
(274,296
)
 
(280,909
)
 
 
 
 
 
Net Decrease in Cash and Cash Equivalents
 
(202
)
 
(44
)
Cash and Cash Equivalents at Beginning of Period
 
2,613

 
2,745

Cash and Cash Equivalents at End of Period
 
$
2,411

 
$
2,701

 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 

 
 

Cash Paid for Interest, Net of Capitalized Amounts
 
$
128,435

 
$
136,919

Net Cash Paid for Income Taxes
 
33,712

 
22,148

Noncash Acquisitions Under Capital Leases
 
2,257

 
3,451

Construction Expenditures Included in Current Liabilities as of September 30,
 
80,990

 
54,463

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.



121




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
Property, Plant and Equipment
Disposition Plant Severance

122





INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES

123




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 approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million. In April 2015, I&M filed a notice with the IURC to exclude $117 million related to certain projects. In September 2015, the IURC granted I&M's motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals.

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 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in the 2014 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 179. 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 a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing.  In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. Plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. Management will continue to defend against the remaining 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 256 for additional discussion of relevant factors.

124



RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions of KWhs)
Retail:
 

 
 

 
 

 
 

Residential
1,441

 
1,347

 
4,311

 
4,413

Commercial
1,342

 
1,264

 
3,744

 
3,681

Industrial
1,972

 
1,933

 
5,712

 
5,701

Miscellaneous
15

 
15

 
50

 
50

Total Retail
4,770

 
4,559

 
13,817

 
13,845

 
 
 
 
 
 
 
 
Wholesale
2,649

 
3,985

 
8,732

 
13,151

 
 
 
 
 
 
 
 
Total KWhs
7,419

 
8,544

 
22,549

 
26,996


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,
 
2015
 
2014
 
2015
 
2014
 
(in degree days)
Actual - Heating (a)

 
6

 
2,931

 
3,222

Normal - Heating (b)
10

 
11

 
2,413

 
2,388

 
 
 
 
 
 
 
 
Actual - Cooling (c)
530

 
410

 
796

 
712

Normal - Cooling (b)
574

 
581

 
836

 
843


(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.


125



Third Quarter of 2015 Compared to Third Quarter of 2014
Reconciliation of Third Quarter of 2014 to Third Quarter of 2015
Net Income
(in millions)
 
 
 
Third Quarter of 2014
 
$
27

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
27

FERC Municipals and Cooperatives
 
7

Off-system Sales
 
(7
)
Transmission Revenues
 
(3
)
Other Revenues
 
6

Total Change in Gross Margin
 
30

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
9

Depreciation and Amortization
 
1

Taxes Other Than Income Taxes
 
1

Other Income
 
(3
)
Interest Expense
 
(1
)
Total Change in Expenses and Other
 
7

 
 
 

Income Tax Expense
 
(7
)
 
 
 

Third Quarter of 2015
 
$
57


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

Retail Margins increased $27 million primarily due to the following:
A $15 million increase resulting from successful rate proceedings in the Indiana service territory.
An $8 million increase in weather-related usage primarily due to a 29% increase in cooling degree days.
A $5 million increase in weather-normalized usage.
These increases were partially offset by:
A $4 million decrease due to increased costs for power acquired under the Unit Power Agreement between AEGCo and I&M.
Margins from FERC Municipal and Cooperatives increased $7 million primarily due to formula rate changes.
Margins from Off-system Sales decreased $7 million due to lower market prices and decreased sales volumes.
Other Revenues increased $6 million primarily due to a 2014 MPSC order disallowing $4 million of lost revenue from 2012 through 2014 related to Demand Side Management.

126



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

Other Operation and Maintenance expenses decreased $9 million primarily due to the following:
An $8 million decrease due to a 2014 accrual for expected environmental remediation costs.
A $5 million decrease in boiler plant maintenance expenses primarily due to the retirement of the Tanners Creek Plant in May 2015.
These decreases were partially offset by:
A $4 million increase in nuclear expenses primarily related to Cook Plant, Unit 1 diesel generator repairs.
Other Income decreased $3 million primarily due to a decrease in AFUDC Equity accrued on nuclear fuel for the reactors at Cook Plant.
Income Tax Expense increased $7 million primarily due to an increase in pretax book income, partially offset by the recording of federal and state income tax adjustments.

127



Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015
Net Income
(in millions)
 
 
 
Nine Months Ended September 30, 2014
 
$
141

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
58

FERC Municipals and Cooperatives
 
32

Off-system Sales
 
(58
)
Other Revenues
 
(2
)
Total Change in Gross Margin
 
30

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
25

Taxes Other Than Income Taxes
 
(2
)
Other Income
 
(2
)
Interest Expense
 
3

Total Change in Expenses and Other
 
24

 
 
 

Income Tax Expense
 
(15
)
 
 
 

Nine Months Ended September 30, 2015
 
$
180


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 $58 million primarily due to the following:
A $42 million increase resulting from successful rate proceedings in the Indiana service territory.
A $12 million decrease in PJM related expenses primarily related to the polar vortex in 2014.
These increases were partially offset by:
A $4 million decrease due to weather-normalized Residential sales.
Margins from FERC Municipal and Cooperatives increased $32 million primarily due to the annual true-up adjustment of formula rates to actual costs.
Margins from Off-system Sales decreased $58 million due to lower market prices and decreased sales volume.
Other Revenues decreased $2 million primarily due to the following:
An $8 million decrease in barging deliveries to the Rockport Plant by River Transportation Division (RTD). The decrease in RTD revenue was offset by a corresponding decrease in Other Operation and Maintenance expenses for barging below.
This decrease was partially offset by:
A $4 million increase relating to a 2014 MPSC order disallowing lost revenue from 2012 through 2014 related to Demand Side Management.
A $1 million increase relating to a net gain on coal procurement sales.




128



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

Other Operation and Maintenance expenses decreased $25 million primarily due to the following:
A $14 million decrease in environmental costs due to a 2014 accrual of $8 million for expected environmental remediation costs and a current year $6 million reduction of an environmental liability.
An $8 million decrease in general and administrative expenses.
An $8 million decrease in distribution expenses primarily due to lower storm restoration and forestry expense.
A $6 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 above.
These decreases were partially offset by:
An $11 million increase in nuclear expenses primarily related to Cook Plant, Unit 1 diesel generator repairs.
Interest Expense decreased $3 million primarily due to a lower interest rate on a remarketed pollution control bonds.
Income Tax Expense increased $15 million primarily due to an increase in pretax book income, partially offset by the recording of federal and state income tax adjustments.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2014 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 256 for a discussion of accounting pronouncements.

129




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
REVENUES
 
 
 
 
 
 
 
 

Electric Generation, Transmission and Distribution
 
$
536,227

 
$
520,881

 
$
1,617,504

 
$
1,642,721

Sales to AEP Affiliates
 
9,677

 
401

 
16,634

 
3,753

Other Revenues – Affiliated
 
21,672

 
20,832

 
62,183

 
70,821

Other Revenues – Nonaffiliated
 
786

 
749

 
2,626

 
1,298

TOTAL REVENUES
 
568,362

 
542,863

 
1,698,947

 
1,718,593

 
 
 
 
 
 
 
 
 
EXPENSES
 
 

 
 

 
 

 
 

Fuel and Other Consumables Used for Electric Generation
 
90,499

 
117,414

 
264,424

 
387,757

Purchased Electricity for Resale
 
41,544

 
20,019

 
147,711

 
52,467

Purchased Electricity from AEP Affiliates
 
67,281

 
66,561

 
182,239

 
203,807

Other Operation
 
141,054

 
144,331

 
407,320

 
431,953

Maintenance
 
53,727

 
59,043

 
160,907

 
161,854

Depreciation and Amortization
 
49,215

 
50,585

 
150,162

 
150,062

Taxes Other Than Income Taxes
 
21,608

 
22,059

 
66,992

 
64,685

TOTAL EXPENSES
 
464,928

 
480,012

 
1,379,755

 
1,452,585

 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
103,434

 
62,851

 
319,192

 
266,008

 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 

 
 

 
 

 
 

Interest Income
 
1,896

 
1,450

 
7,222

 
4,228

Allowance for Equity Funds Used During Construction
 
2,157

 
5,596

 
9,107

 
14,364

Interest Expense
 
(23,144
)
 
(22,617
)
 
(68,889
)
 
(71,955
)
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
84,343

 
47,280

 
266,632

 
212,645

 
 
 
 
 
 
 
 
 
Income Tax Expense
 
27,691

 
20,654

 
86,725

 
71,596

 
 
 
 
 
 
 
 
 
NET INCOME
 
$
56,652

 
$
26,626

 
$
179,907

 
$
141,049

The common stock of I&M is wholly-owned by AEP.
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.


130



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
Net Income
 
$
56,652

 
$
26,626

 
$
179,907

 
$
141,049

 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME, NET OF TAXES
 
 

 
 

 
 

 
 

Cash Flow Hedges, Net of Tax of $144 and $220 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $432 and $638 for the Nine Months Ended September 30, 2015 and 2014, Respectively
 
267

 
410

 
802

 
1,185

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $6 and $22 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $18 and $68 for the Nine Months Ended September 30, 2015 and 2014, Respectively
 
11

 
42

 
33

 
128

 
 
 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE INCOME
 
278

 
452

 
835

 
1,313

 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
$
56,930

 
$
27,078

 
$
180,742

 
$
142,362

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

131



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
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

 
 

 
 

 
 

 
 

 
 

TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2014
$
56,584

 
$
980,896

 
$
930,829

 
$
(14,360
)
 
$
1,953,949

 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 

 
 

 
(90,000
)
 
 

 
(90,000
)
Net Income
 

 
 

 
179,907

 
 

 
179,907

Other Comprehensive Income
 

 
 

 
 

 
835

 
835

TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2015
$
56,584

 
$
980,896

 
$
1,020,736

 
$
(13,525
)
 
$
2,044,691

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

132



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2015 and December 31, 2014
(in thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2015
 
2014
CURRENT ASSETS
 
 
 
 
Cash and Cash Equivalents
 
$
1,264

 
$
1,020

Advances to Affiliates
 
13,508

 
13,481

Accounts Receivable:
 
 
 
 
Customers
 
58,950

 
56,978

Affiliated Companies
 
63,135

 
72,582

Accrued Unbilled Revenues
 
2,254

 
503

Miscellaneous
 
1,409

 
1,625

Allowance for Uncollectible Accounts
 
(21
)
 
(494
)
Total Accounts Receivable
 
125,727

 
131,194

Fuel
 
24,687

 
54,623

Materials and Supplies
 
189,764

 
201,089

Risk Management Assets – Nonaffiliated
 
8,574

 
22,328

Risk Management Assets – Affiliated
 
2,053

 

Accrued Tax Benefits
 
6,232

 
24,788

Prepayments and Other Current Assets
 
27,549

 
27,968

TOTAL CURRENT ASSETS
 
399,358

 
476,491

 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
Electric:
 
 
 
 
Generation
 
3,968,224

 
3,741,831

Transmission
 
1,380,689

 
1,358,419

Distribution
 
1,758,347

 
1,698,409

Other Property, Plant and Equipment (September 30, 2015 and December 31, 2014 Amounts Include Coal Mining and Nuclear Fuel, December 31, 2014 Amount Includes 2015 Plant Retirement)
 
745,858

 
1,490,820

Construction Work in Progress
 
470,794

 
537,237

Total Property, Plant and Equipment
 
8,323,912

 
8,826,716

Accumulated Depreciation, Depletion and Amortization
 
3,084,188

 
3,410,341

TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
5,239,724

 
5,416,375

 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
Regulatory Assets
 
818,168

 
536,152

Spent Nuclear Fuel and Decommissioning Trusts
 
2,047,260

 
2,095,732

Long-term Risk Management Assets – Nonaffiliated
 
1,338

 
3,317

Deferred Charges and Other Noncurrent Assets
 
123,676

 
137,209

TOTAL OTHER NONCURRENT ASSETS
 
2,990,442

 
2,772,410

 
 
 
 
 
TOTAL ASSETS
 
$
8,629,524

 
$
8,665,276

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

133



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
September 30, 2015 and December 31, 2014
(dollars in thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2015
 
2014
CURRENT LIABILITIES
 
 
 
 
Advances from Affiliates
 
$
151,004

 
$
142,501

Accounts Payable:
 
 
 
 
General
 
132,292

 
168,294

Affiliated Companies
 
70,812

 
76,010

Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2015 and December 31, 2014 Amounts Include $97,953 and $85,657, Respectively, Related to DCC Fuel)
 
301,148

 
382,187

Risk Management Liabilities – Nonaffiliated
 
4,615

 
5,223

Customer Deposits
 
35,641

 
35,206

Accrued Taxes
 
58,791

 
72,742

Accrued Interest
 
13,263

 
26,677

Obligations Under Capital Leases
 
40,375

 
42,050

Other Current Liabilities
 
151,489

 
150,566

TOTAL CURRENT LIABILITIES
 
959,430

 
1,101,456

 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
Long-term Debt – Nonaffiliated
 
1,759,503

 
1,645,210

Long-term Risk Management Liabilities – Nonaffiliated
 
1,248

 
1,395

Deferred Income Taxes
 
1,329,163

 
1,264,167

Regulatory Liabilities and Deferred Investment Tax Credits
 
1,041,910

 
1,199,694

Asset Retirement Obligations
 
1,379,004

 
1,337,179

Deferred Credits and Other Noncurrent Liabilities
 
114,575

 
162,226

TOTAL NONCURRENT LIABILITIES
 
5,625,403

 
5,609,871

 
 
 
 
 
TOTAL LIABILITIES
 
6,584,833

 
6,711,327

 
 
 
 
 
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
 
1,020,736

 
930,829

Accumulated Other Comprehensive Income (Loss)
 
(13,525
)
 
(14,360
)
TOTAL COMMON SHAREHOLDER’S EQUITY
 
2,044,691

 
1,953,949

 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
8,629,524

 
$
8,665,276

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

134



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
Nine Months Ended September 30,
 
 
2015
 
2014
OPERATING ACTIVITIES
 
 

 
 

Net Income
 
$
179,907

 
$
141,049

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

 
 

Depreciation and Amortization
 
150,162

 
150,062

Deferred Income Taxes
 
38,338

 
15,792

Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net
 
(148
)
 
23,951

Allowance for Equity Funds Used During Construction
 
(9,107
)
 
(14,364
)
Mark-to-Market of Risk Management Contracts
 
12,926

 
(2,196
)
Amortization of Nuclear Fuel
 
101,649

 
114,238

Fuel Over/Under-Recovery, Net
 
(16,055
)
 
18,931

Change in Other Noncurrent Assets
 
27,286

 
(36,596
)
Change in Other Noncurrent Liabilities
 
(6,330
)
 
66,502

Changes in Certain Components of Working Capital:
 
 

 
 

Accounts Receivable, Net
 
5,467

 
59,646

Fuel, Materials and Supplies
 
29,609

 
14,884

Accounts Payable
 
(14,001
)
 
(12,052
)
Accrued Taxes, Net
 
4,605

 
30,719

Other Current Assets
 
6,923

 
11,741

Other Current Liabilities
 
(9,276
)
 
(8,201
)
Net Cash Flows from Operating Activities
 
501,955

 
574,106

 
 
 
 
 
INVESTING ACTIVITIES
 
 

 
 

Construction Expenditures
 
(337,021
)
 
(345,369
)
Change in Advances to Affiliates, Net
 
(27
)
 
42,364

Purchases of Investment Securities
 
(1,479,149
)
 
(789,461
)
Sales of Investment Securities
 
1,437,336

 
746,272

Acquisitions of Nuclear Fuel
 
(53,262
)
 
(109,224
)
Other Investing Activities
 
9,000

 
11,773

Net Cash Flows Used for Investing Activities
 
(423,123
)
 
(443,645
)
 
 
 
 
 
FINANCING ACTIVITIES
 
 

 
 

Issuance of Long-term Debt – Nonaffiliated
 
210,687

 
99,323

Change in Advances from Affiliates, Net
 
8,503

 
95,899

Retirement of Long-term Debt – Nonaffiliated
 
(178,471
)
 
(190,550
)
Principal Payments for Capital Lease Obligations
 
(29,875
)
 
(35,660
)
Dividends Paid on Common Stock
 
(90,000
)
 
(100,000
)
Other Financing Activities
 
568

 
628

Net Cash Flows Used for Financing Activities
 
(78,588
)
 
(130,360
)
 
 
 
 
 
Net Increase in Cash and Cash Equivalents
 
244

 
101

Cash and Cash Equivalents at Beginning of Period
 
1,020

 
1,317

Cash and Cash Equivalents at End of Period
 
$
1,264

 
$
1,418

 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 

 
 

Cash Paid for Interest, Net of Capitalized Amounts
 
$
77,450

 
$
75,789

Net Cash Paid (Received) for Income Taxes
 
17,203

 
(1,475
)
Noncash Acquisitions Under Capital Leases
 
1,990

 
5,015

Construction Expenditures Included in Current Liabilities as of September 30,
 
51,582

 
69,241

Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,
 
31,140

 
11

Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage
 
2,136

 
3,208

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

135




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
Property, Plant and Equipment
Disposition Plant Severance

136





OHIO POWER COMPANY AND SUBSIDIARIES


137




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

EXECUTIVE OVERVIEW

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. In June 2015, the Supreme Court of Ohio issued a decision that reversed, as requested by OPCo, the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. In September 2015, the Supreme Court of Ohio denied the IEU's request for reconsideration and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate.

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 established 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 $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, which has scheduled oral arguments for the fourth quarter of 2015.

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 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. In April 2015, the PUCO issued an order that approved, with modifications, OPCo's July 2014 application to collect the unrecovered portion of the deferred capacity costs. In May 2015, the PUCO granted intervenors requests for rehearing. As of September 30, 2015, OPCo’s net deferred capacity costs balance was $392 million, including debt carrying costs. Through September 30, 2015, OPCo has collected $183 million in deferred capacity costs, and related carrying charges.

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. 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.

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 October 2014, the independent auditor, selected by the PUCO, 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/MW day capacity charge, the independent auditor has recommended a methodology for calculating

138



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 disagrees with the findings in the audit report.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.

June 2015 - May 2018 ESP Including PPA Application

In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018. The proposal also included 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 PPA.

In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the Distribution Investment Rider (DIR) with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo's and various intervenors' requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider.

In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. A hearing at the PUCO related to the PPA commenced in September 2015. In October 2015, the PUCO staff submitted testimony that opposed the PPA application as currently proposed but concluded that, with changes, a PPA could be in the public interest.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, 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 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in the 2014 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 179. 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 256 for additional discussion of relevant factors.


139



RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions of KWhs)
Retail:
 

 
 

 
 

 
 

Residential
3,788

 
3,513

 
11,249

 
11,189

Commercial
3,929

 
3,714

 
11,074

 
10,838

Industrial
3,711

 
3,647

 
11,081

 
10,822

Miscellaneous
28

 
26

 
88

 
88

Total Retail (a)
11,456

 
10,900

 
33,492

 
32,937

 
 
 
 
 
 
 
 
Wholesale (b)
497

 
575

 
1,460

 
1,727

 
 
 
 
 
 
 
 
Total KWhs
11,953

 
11,475

 
34,952

 
34,664


(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,
 
 
2015
 
2014
 
2015
 
2014
 
 
(in degree days)
Actual - Heating (a)
 

 
1

 
2,575

 
2,540

Normal - Heating (b)
 
6

 
7

 
2,073

 
2,074

 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
620

 
581

 
970

 
943

Normal - Cooling (b)
 
666

 
663

 
956

 
946


(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.

140



Third Quarter of 2015 Compared to Third Quarter of 2014
Reconciliation of Third Quarter of 2014 to Third Quarter of 2015
Net Income
(in millions)
 
 
 
Third Quarter of 2014
 
$
54

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
106

Off-system Sales
 
(10
)
Transmission Revenues
 
(37
)
Other Revenues
 
1

Total Change in Gross Margin
 
60

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(11
)
Depreciation and Amortization
 
(9
)
Taxes Other Than Income Taxes
 
(4
)
Carrying Costs Income
 
(7
)
Interest Expense
 
(1
)
Total Change in Expenses and Other
 
(32
)
 
 
 

Income Tax Expense
 
(10
)
 
 
 

Third Quarter of 2015
 
$
72


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 $106 million primarily due to the following:
A $65 million increase in transmission and PJM revenues primarily due to the energy supplied as result of the Ohio auction and a regulatory change which resulted in revenues collected through a non-bypassable transmission rider, partially offset by a corresponding decrease in Transmission Revenues below.
A $33 million regulatory provision recorded in 2014.
A $7 million increase in revenues associated with the Distribution Investment Rider.
A $7 million increase in revenues associated with the gridSMART®, Enhanced Service Reliability and Retail Stability Riders. These riders have corresponding increases in other expense items below.
These increases were partially offset by:
A $14 million decrease in base rates due to the discontinuance of seasonal rates.
A $14 million decrease in revenues associated with the recovery of 2012 storm costs under the Storm Damage Recovery Rider which ended in April 2015. This decrease in Retail Margins is primarily offset by a decrease in Other Operation and Maintenance expenses below.
Margins from Off-system Sales decreased $10 million primarily due to losses from a legacy power contract.
Transmission Revenues decreased $37 million primarily due to a decrease in Network Integrated Transmission Service (NITS) revenue due to OPCo assuming the responsibility for items determined to be cost-based transmission-related charges that were the responsibility of the CRES providers prior to June 2015, partially offset by a corresponding increase in Retail Margins above.


141



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

Other Operation and Maintenance expenses increased $11 million primarily due to the following:
A $19 million increase in recoverable PJM expenses.
A $4 million increase in employee-related expenses.
These increases were partially offset by:
A $14 million decrease due to the completion of the amortization of 2012 deferred storm expenses in April 2015. This decrease was offset by a corresponding decrease in Retail Margins above.
Depreciation and Amortization expenses increased $9 million primarily due to the following:
A $4 million increase in amortization expenses for the collection of carrying costs on deferred capacity charges beginning June 2015. This increase was offset by a corresponding increase in Retail Margins above.
A $3 million increase in depreciation expense primarily due to an increase in depreciable base of transmission and distribution assets.
A $3 million increase in gridSMART® capital carrying charges primarily due to a rider rate increase effective June 2015. This increase was offset by a corresponding increase in Retail Margins above.
Taxes Other Than Income Taxes increased $4 million primarily due to an increase in property taxes due to additional investment in transmission and distribution assets and higher tax rates.
Carrying Costs Income decreased $7 million primarily due to the collection of carrying costs on deferred capacity charges beginning June 2015.
Income Tax Expense increased $10 million primarily due to an increase in pretax book income.


142



Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015
Net Income
(In Millions)
 
 
 
Nine Months Ended September 30, 2014
 
$
171

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
133

Off-system Sales
 
(12
)
Transmission Revenues
 
(72
)
Other Revenues
 
8

Total Change in Gross Margin
 
57

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(3
)
Depreciation and Amortization
 
(13
)
Taxes Other Than Income Taxes
 
(14
)
Other Income
 
(2
)
Carrying Costs Income
 
(10
)
Interest Expense
 
1

Total Change in Expenses and Other
 
(41
)
 
 
 

Income Tax Expense
 
(2
)
 
 
 

Nine Months Ended September 30, 2015
 
$
185


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 $133 million primarily due to the following:
A $91 million increase in transmission and PJM revenues primarily due to the energy supplied as result of the Ohio auction and a regulatory change which resulted in revenues collected through a non-bypassable transmission rider, partially offset by a corresponding decrease in Transmission Revenues below.
A $33 million regulatory provision recorded in 2014.
A $22 million increase in revenues associated with the Distribution Investment Rider.
A $14 million increase in revenues associated with the gridSMART®, Enhanced Service Reliability and Retail Stability Riders. These riders have corresponding increases in other expense items below.
These increases were partially offset by:
A $19 million decrease in the Energy Efficiency (EE), Peak Demand Reduction Cost Recovery Rider (PDR) revenues and associated deferrals. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
An $11 million decrease in revenues associated with the recovery of 2012 storm costs under the Storm Damage Recovery Rider which ended in April 2015. This decrease in Retail Margins is primarily offset by a decrease in Other Operation and Maintenance expenses below.
A $6 million decrease in revenues associated with the Universal Service Fund (USF) surcharge. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
A $4 million decrease in base rates due to the discontinuance of seasonal rates.
Margins from Off-system Sales decreased $12 million primarily due to losses from a legacy power contract.
Transmission Revenues decreased $72 million primarily due to the following:
A $44 million decrease in NITS revenue primarily due to OPCo assuming the responsibility for items determined to be cost-based transmission-related charges that were the responsibility of the CRES providers prior to June 2015, partially offset by a corresponding increase in Retail Margins above.
A $12 million decrease in revenues related to a lower annual transmission formula rate true-up.
A $9 million transmission regulatory settlement in 2015.
Other Revenues increased $8 million primarily due to increased pole attachment revenue.

143



Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $3 million primarily due to the following:
A $33 million increase in recoverable PJM expenses.
A $6 million increase due to PUCO ordered contributions to the Ohio Growth Fund.
These increases were partially offset by:
A $19 million decrease in EE and PDR costs and associated deferrals. This decrease was offset by a corresponding decrease in Retail Margins above.
A $12 million decrease due to the completion of the amortization of 2012 deferred storm expenses in April 2015. This decrease was offset by a corresponding decrease in Retail Margins above.
A $6 million decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset by a corresponding decrease in Retail Margins above.
Depreciation and Amortization expenses increased $13 million primarily due to the following:
A $9 million increase in depreciation expense primarily due to an increase in depreciable base of transmission and distribution assets.
A $5 million increase in amortization expenses for the collection of carrying costs on deferred capacity charges beginning June 2015. This increase was offset by a corresponding increase in Retail Margins above.
Taxes Other Than Income Taxes increased $14 million primarily due to an increase in property taxes due to additional investment in transmission and distribution assets and higher tax rates.
Carrying Costs Income decreased $10 million primarily due to the collection of carrying costs on deferred capacity charges beginning June 2015.

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 2014 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 256 for a discussion of accounting pronouncements.


144




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
REVENUES
 
 
 
 
 
 
 
 

Electricity, Transmission and Distribution
 
$
775,905

 
$
793,900

 
$
2,320,372

 
$
2,380,768

Sales to AEP Affiliates
 
4,426

 
43,733

 
79,690

 
120,154

Other Revenues
 
1,953

 
1,564

 
6,416

 
4,628

TOTAL REVENUES
 
782,284

 
839,197

 
2,406,478

 
2,505,550

 
 
 
 
 
 
 
 
 
EXPENSES
 
 

 
 

 
 

 
 

Purchased Electricity for Resale
 
173,094

 
48,541

 
431,608

 
191,730

Purchased Electricity from AEP Affiliates
 
45,834

 
315,903

 
462,645

 
897,658

Amortization of Generation Deferrals
 
55,466

 
26,655

 
122,221

 
82,818

Other Operation
 
170,144

 
145,163

 
446,817

 
428,074

Maintenance
 
39,437

 
53,724

 
121,224

 
136,965

Depreciation and Amortization
 
63,757

 
54,968

 
178,609

 
165,152

Taxes Other Than Income Taxes
 
93,666

 
89,564

 
283,092

 
268,734

TOTAL EXPENSES
 
641,398

 
734,518

 
2,046,216

 
2,171,131

 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
140,886

 
104,679

 
360,262

 
334,419

 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 

 
 

 
 

 
 

Interest Income
 
1,165

 
1,986

 
4,328

 
8,159

Carrying Costs Income (Expense)
 
(1,576
)
 
5,606

 
10,037

 
19,594

Allowance for Equity Funds Used During Construction
 
2,228

 
1,825

 
7,015

 
4,893

Interest Expense
 
(32,593
)
 
(31,171
)
 
(96,313
)
 
(96,937
)
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
110,110

 
82,925

 
285,329

 
270,128

 
 
 
 
 
 
 
 
 
Income Tax Expense
 
38,541

 
28,865

 
100,641

 
98,759

 
 
 
 
 
 
 
 
 
NET INCOME
 
$
71,569

 
$
54,060

 
$
184,688

 
$
171,369

The common stock of OPCo is wholly-owned by AEP.
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.


145



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
Net Income
 
$
71,569

 
$
54,060

 
$
184,688

 
$
171,369

 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE LOSS, NET OF TAXES
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $185 and $185 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $555 and $611 for the Nine Months Ended September 30, 2015 and 2014, Respectively
 
(344
)
 
(343
)
 
(1,030
)
 
(1,134
)
 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
$
71,225

 
$
53,717

 
$
183,658

 
$
170,235

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.


146



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
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

 
 

 
 

 
 

 
 

 
 

TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2014
$
321,201

 
$
838,782

 
$
814,625

 
$
5,602

 
$
1,980,210

 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 

 
 

 
(156,250
)
 
 

 
(156,250
)
Net Income
 

 
 

 
184,688

 
 

 
184,688

Other Comprehensive Loss
 

 
 

 
 

 
(1,030
)
 
(1,030
)
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2015
$
321,201

 
$
838,782

 
$
843,063

 
$
4,572

 
$
2,007,618

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.
 


147



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2015 and December 31, 2014
(in thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2015
 
2014
CURRENT ASSETS
 
 
 
 
Cash and Cash Equivalents
 
$
3,248

 
$
2,870

Restricted Cash for Securitized Funding
 
16,195

 
28,687

Advances to Affiliates
 
279,129

 
312,473

Accounts Receivable:
 
 
 
 
Customers
 
35,711

 
57,906

Affiliated Companies
 
57,240

 
79,822

Accrued Unbilled Revenues
 
39,236

 
35,755

Miscellaneous
 
1,246

 
927

Allowance for Uncollectible Accounts
 
(421
)
 
(171
)
Total Accounts Receivable
 
133,012

 
174,239

Notes Receivable Due Within One Year – Affiliated
 

 
86,000

Materials and Supplies
 
75,878

 
60,909

Risk Management Assets
 

 
7,242

Deferred Income Tax Benefits
 
20,568

 
49,306

Accrued Tax Benefits
 
5,030

 
6,100

Prepayments and Other Current Assets
 
11,141

 
8,997

TOTAL CURRENT ASSETS
 
544,201

 
736,823

 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
Electric:
 
 
 
 
Transmission
 
2,181,389

 
2,104,613

Distribution
 
4,231,051

 
4,087,601

Other Property, Plant and Equipment
 
446,485

 
390,848

Construction Work in Progress
 
212,093

 
218,667

Total Property, Plant and Equipment
 
7,071,018

 
6,801,729

Accumulated Depreciation and Amortization
 
2,086,931

 
2,038,120

TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
4,984,087

 
4,763,609

 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
Notes Receivable – Affiliated
 
32,245

 
32,245

Regulatory Assets
 
1,150,864

 
1,318,939

Securitized Assets
 
91,899

 
109,999

Long-term Risk Management Assets
 
23,265

 
45,102

Deferred Charges and Other Noncurrent Assets
 
118,942

 
264,150

TOTAL OTHER NONCURRENT ASSETS
 
1,417,215

 
1,770,435

 
 
 
 
 
TOTAL ASSETS
 
$
6,945,503

 
$
7,270,867

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.


148



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
September 30, 2015 and December 31, 2014
(dollars in thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2015
 
2014
CURRENT LIABILITIES
 
 
 
 
Accounts Payable:
 
 

 
 

General
 
$
141,073

 
$
145,328

Affiliated Companies
 
88,324

 
172,741

Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2015 and December 31, 2014 Amounts Include $45,864 and $45,427, Respectively, Related to Ohio Phase-in-Recovery Funding)
 
395,938

 
131,497

Risk Management Liabilities
 
2,823

 
1,943

Customer Deposits
 
60,235

 
53,922

Accrued Taxes
 
285,003

 
420,772

Accrued Interest
 
45,452

 
34,279

Other Current Liabilities
 
147,567

 
179,093

TOTAL CURRENT LIABILITIES
 
1,166,415

 
1,139,575

 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
Long-term Debt – Nonaffiliated
(September 30, 2015 and December 31, 2014 Amounts Include $141,177 and $187,041, Respectively, Related to Ohio Phase-in-Recovery Funding)
 
1,770,112

 
2,165,626

Long-term Risk Management Liabilities
 
4,871

 
3,013

Deferred Income Taxes
 
1,402,369

 
1,405,620

Regulatory Liabilities and Deferred Investment Tax Credits
 
535,458

 
514,691

Employee Benefits and Pension Obligations
 
29,978

 
36,662

Deferred Credits and Other Noncurrent Liabilities
 
28,682

 
25,470

TOTAL NONCURRENT LIABILITIES
 
3,771,470

 
4,151,082

 
 
 
 
 
TOTAL LIABILITIES
 
4,937,885

 
5,290,657

 
 
 
 
 
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
 
838,782

 
838,782

Retained Earnings
 
843,063

 
814,625

Accumulated Other Comprehensive Income (Loss)
 
4,572

 
5,602

TOTAL COMMON SHAREHOLDER’S EQUITY
 
2,007,618

 
1,980,210

 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
6,945,503

 
$
7,270,867

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.


149



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
Nine Months Ended September 30,
 
 
2015
 
2014
OPERATING ACTIVITIES
 
 

 
 

Net Income
 
$
184,688

 
$
171,369

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

 
 

Depreciation and Amortization
 
178,609

 
165,152

Amortization of Generation Deferrals
 
122,221

 
82,818

Deferred Income Taxes
 
28,099

 
27,990

Carrying Costs Income
 
(10,037
)
 
(19,594
)
Allowance for Equity Funds Used During Construction
 
(7,015
)
 
(4,893
)
Mark-to-Market of Risk Management Contracts
 
31,818

 
(5,003
)
Pension Contributions to Qualified Plan Trust
 
(7,671
)
 
(6,547
)
Property Taxes
 
148,407

 
148,124

Fuel Over/Under-Recovery, Net
 
(15,674
)
 
37,326

Deferral of Ohio Capacity Costs, Net
 
(30,662
)
 
(138,737
)
Change in Other Noncurrent Assets
 
29,168

 
35,962

Change in Other Noncurrent Liabilities
 
30,913

 
59,081

Changes in Certain Components of Working Capital:
 
 

 
 

Accounts Receivable, Net
 
41,227

 
(20,395
)
Materials and Supplies
 
(14,969
)
 
(1,247
)
Accounts Payable
 
(78,831
)
 
(83,029
)
Customer Deposits
 
6,313

 
2,973

Accrued Taxes, Net
 
(134,699
)
 
(173,470
)
Other Current Assets
 
(3,233
)
 
(947
)
Other Current Liabilities
 
(4,707
)
 
26,039

Net Cash Flows from Operating Activities
 
493,965

 
302,972

 
 
 
 
 
INVESTING ACTIVITIES
 
 

 
 

Construction Expenditures
 
(346,831
)
 
(327,972
)
Change in Restricted Cash for Securitized Funding
 
12,492

 
1,653

Change in Advances to Affiliates, Net
 
33,344

 
315,325

Proceeds from Notes Receivable – Affiliated
 
86,000

 
178,580

Other Investing Activities
 
10,882

 
6,807

Net Cash Flows from (Used for) Investing Activities
 
(204,113
)
 
174,393

 
 
 
 
 
FINANCING ACTIVITIES
 
 

 
 

Retirement of Long-term Debt – Nonaffiliated
 
(131,484
)
 
(438,583
)
Principal Payments for Capital Lease Obligations
 
(2,937
)
 
(3,912
)
Dividends Paid on Common Stock
 
(156,250
)
 
(35,000
)
Other Financing Activities
 
1,197

 
1,015

Net Cash Flows Used for Financing Activities
 
(289,474
)
 
(476,480
)
 
 
 
 
 
Net Increase in Cash and Cash Equivalents
 
378

 
885

Cash and Cash Equivalents at Beginning of Period
 
2,870

 
3,004

Cash and Cash Equivalents at End of Period
 
$
3,248

 
$
3,889

 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 

 
 

Cash Paid for Interest, Net of Capitalized Amounts
 
$
79,019

 
$
90,188

Net Cash Paid for Income Taxes
 
24,060

 
15,523

Noncash Acquisitions Under Capital Leases
 
2,115

 
4,505

Construction Expenditures Included in Current Liabilities as of September 30,
 
30,209

 
45,691

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.


150




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
Benefit Plans
Business Segments
Derivatives and Hedging
Fair Value Measurements
Income Taxes
Financing Activities
Variable Interest Entities
Property, Plant and Equipment
Disposition Plant Severance




151





PUBLIC SERVICE COMPANY OF OKLAHOMA

152




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

EXECUTIVE OVERVIEW

Regulatory Activity

2015 Oklahoma Base Rate Case

In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million, which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service.

In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million, will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC.

In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million, based upon returns on common equity ranging from 8.75% to 9.3%, and increases to depreciation expense ranging from $23 million to $46 million. Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certain intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC are scheduled for December 2015. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2015 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 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in the 2014 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 179. 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 256 for additional discussion of relevant factors.


153



RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions of KWhs)
Retail:
 

 
 

 
 

 
 

Residential
2,126

 
1,981

 
4,966

 
4,978

Commercial
1,568

 
1,455

 
4,028

 
3,905

Industrial
1,408

 
1,407

 
4,039

 
3,939

Miscellaneous
365

 
356

 
958

 
956

Total Retail
5,467

 
5,199

 
13,991

 
13,778

 
 
 
 
 
 
 
 
Wholesale
28

 
42

 
166

 
318

 
 
 
 
 
 
 
 
Total KWhs
5,495

 
5,241

 
14,157

 
14,096


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,
 
2015
 
2014
 
2015
 
2014
 
(in degree days)
Actual - Heating (a)

 

 
1,176

 
1,417

Normal - Heating (b)
1

 
1

 
1,089

 
1,086

 
 
 
 
 
 
 
 
Actual - Cooling (c)
1,444

 
1,259

 
2,103

 
1,935

Normal - Cooling (b)
1,387

 
1,394

 
2,053

 
2,058


(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.

154



Third Quarter of 2015 Compared to Third Quarter of 2014
Reconciliation of Third Quarter of 2014 to Third Quarter of 2015
Net Income
(in millions)
 
 
 
Third Quarter of 2014
 
$
45

 
 
 
Changes in Gross Margin:
 
 
Retail Margins (a)
 
13

Transmission Revenues
 
1

Other Revenues
 
1

Total Change in Gross Margin
 
15

 
 
 
Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(11
)
Depreciation and Amortization
 
(6
)
Allowance for Equity Funds Used During Construction
 
2

Interest Expense
 
(1
)
Total Change in Expenses and Other
 
(16
)
 
 
 

Income Tax Expense
 
1

 
 
 

Third Quarter of 2015
 
$
45


(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 $13 million primarily due to the following:
An $11 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.
A $9 million increase in weather-related usage primarily due to a 15% increase in cooling degree days.
These increases were partially offset by:
An $8 million decrease primarily due to lower weather-normalized residential sales.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $11 million primarily due to the following:
A $5 million increase in distribution expenses primarily due to increased vegetation management expenses and amortization of 2013 storm restoration expenses beginning in the second quarter of 2015.
A $2 million increase in generation plant maintenance expenses.
A $2 million increase in transmission expenses primarily due to increased SPP transmission services.
Depreciation and Amortization expenses increased $6 million primarily due to the following:
A $4 million increase in amortization related to an advanced metering rider implemented in November 2014.
A $2 million increase due to a higher depreciable base.

155



Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015
Net Income
(in millions)
 
 
 
Nine Months Ended September 30, 2014
 
$
76

 
 
 

Changes in Gross Margin:
 
 

Retail Margins (a)
 
32

Transmission Revenues
 
2

Other Revenues
 
1

Total Change in Gross Margin
 
35

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(5
)
Depreciation and Amortization
 
(17
)
Allowance for Equity Funds Used During Construction
 
4

Interest Expense
 
(3
)
Total Change in Expenses and Other
 
(21
)
 
 
 

Income Tax Expense
 
(4
)
 
 
 

Nine Months Ended September 30, 2015
 
$
86


(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 $32 million primarily due to the following:
A $27 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.
A $7 million net increase in weather-related usage primarily due to a 9% increase in cooling degree days, partially offset by a decrease in heating degree days.
These increases were partially offset by:
A $3 million decrease primarily due to lower weather-normalized residential sales.

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

Other Operation and Maintenance expenses increased $5 million primarily due to the following:
A $3 million increase in distribution expenses primarily due to amortization of 2013 storm restoration expenses beginning in the second quarter of 2015.
A $3 million increase in transmission expenses primarily due to increased SPP transmission services.
A $2 million increase in energy efficiency program expenses.
These increases were partially offset by:
A $3 million decrease in generation plant maintenance expenses.
Depreciation and Amortization expenses increased $17 million primarily due to the following:
A $10 million increase in amortization related to an advanced metering rider implemented in November 2014.
A $6 million increase due to a higher depreciable base.
Allowance for Equity Funds Used During Construction increased $4 million primarily due to increased environmental projects.
Interest Expense increased $3 million primarily due to increased long-term debt outstanding.
Income Tax Expense increased $4 million primarily due to an increase in pretax book income.


156



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 2014 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 256 for a discussion of accounting pronouncements.

157




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
REVENUES
 
 
 
 
 
 
 
 

Electric Generation, Transmission and Distribution
 
$
418,592

 
$
415,193

 
$
1,040,876

 
$
1,028,427

Sales to AEP Affiliates
 
1,062

 
789

 
3,505

 
6,240

Other Revenues
 
709

 
1,009

 
2,258

 
2,524

TOTAL REVENUES
 
420,363

 
416,991

 
1,046,639

 
1,037,191

 
 
 
 
 
 
 
 
 
EXPENSES
 
 

 
 

 
 

 
 

Fuel and Other Consumables Used for Electric Generation
 
87,680

 
85,018

 
226,260

 
192,567

Purchased Electricity for Resale
 
103,226

 
117,521

 
253,785

 
301,816

Purchased Electricity from AEP Affiliates
 

 

 

 
11,024

Other Operation
 
77,541

 
71,605

 
199,334

 
193,101

Maintenance
 
27,239

 
21,800

 
74,322

 
76,223

Depreciation and Amortization
 
30,832

 
24,496

 
90,148

 
73,085

Taxes Other Than Income Taxes
 
9,327

 
9,137

 
27,843

 
27,757

TOTAL EXPENSES
 
335,845

 
329,577

 
871,692

 
875,573

 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
84,518

 
87,414

 
174,947

 
161,618

 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 

 
 

 
 

 
 

Interest Income
 
127

 
137

 
255

 
138

Allowance for Equity Funds Used During Construction
 
2,342

 
194

 
5,952

 
2,215

Interest Expense
 
(14,950
)
 
(13,913
)
 
(44,372
)
 
(41,009
)
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
72,037

 
73,832

 
136,782

 
122,962

 
 
 
 
 
 
 
 
 
Income Tax Expense
 
27,298

 
28,746

 
51,260

 
46,979

 
 
 
 
 
 
 
 
 
NET INCOME
 
$
44,739

 
$
45,086

 
$
85,522

 
$
75,983

The common stock of PSO is wholly-owned by AEP.
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

158



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
Net Income
 
$
44,739

 
$
45,086

 
$
85,522

 
$
75,983

 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE LOSS, NET OF TAXES
 
 

 
 

 
 

 
 

Cash Flow Hedges, Net of Tax of $101 and $102 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $306 and $337 for the Nine Months Ended September 30, 2015 and 2014, Respectively
 
(189
)
 
(190
)
 
(569
)
 
(626
)
 
 
 

 
 

 
 

 
 

TOTAL COMPREHENSIVE INCOME
 
$
44,550

 
$
44,896

 
$
84,953

 
$
75,357

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

159



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
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

 
 

 
 

 
 

 
 

 
 

TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2014
$
157,230

 
$
364,037

 
$
502,005

 
$
4,943

 
$
1,028,215

 
 
 
 
 
 
 
 
 
 
Net Income
 

 
 

 
85,522

 
 

 
85,522

Other Comprehensive Loss
 

 
 

 
 

 
(569
)
 
(569
)
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2015
$
157,230

 
$
364,037

 
$
587,527

 
$
4,374

 
$
1,113,168

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.


160



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2015 and December 31, 2014
(in thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2015
 
2014
CURRENT ASSETS
 
 
 
 
Cash and Cash Equivalents
 
$
1,663

 
$
1,352

Advances to Affiliates
 
116,345

 

Accounts Receivable:
 
 
 
 
Customers
 
24,770

 
28,448

Affiliated Companies
 
25,117

 
22,114

Miscellaneous
 
9,559

 
6,026

Allowance for Uncollectible Accounts
 
(359
)
 
(147
)
Total Accounts Receivable
 
59,087

 
56,441

Fuel
 
15,864

 
16,436

Materials and Supplies
 
52,519

 
50,880

Risk Management Assets
 
1,035

 

Deferred Income Tax Benefits
 
8,975

 

Accrued Tax Benefits
 
19,093

 
24,369

Regulatory Asset for Under-Recovered Fuel Costs
 

 
35,699

Prepayments and Other Current Assets
 
7,280

 
6,524

TOTAL CURRENT ASSETS
 
281,861

 
191,701

 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
Electric:
 
 
 
 
Generation
 
1,296,921

 
1,264,724

Transmission
 
805,505

 
788,911

Distribution
 
2,185,778

 
2,080,221

Other Property, Plant and Equipment (Including Plant to be Retired)
 
435,807

 
421,568

Construction Work in Progress
 
274,470

 
204,753

Total Property, Plant and Equipment
 
4,998,481

 
4,760,177

Accumulated Depreciation and Amortization
 
1,383,116

 
1,319,554

TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
3,615,365

 
3,440,623

 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
Regulatory Assets
 
180,605

 
154,327

Employee Benefits and Pension Assets
 
21,231

 
19,335

Deferred Charges and Other Noncurrent Assets
 
15,664

 
7,557

TOTAL OTHER NONCURRENT ASSETS
 
217,500

 
181,219

 
 
 
 
 
TOTAL ASSETS
 
$
4,114,726

 
$
3,813,543

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

161



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
September 30, 2015 and December 31, 2014
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2015
 
2014
 
 
(in thousands)
CURRENT LIABILITIES
 
 
 
 
Advances from Affiliates
 
$

 
$
154,249

Accounts Payable:
 
 

 
 

General
 
98,777

 
92,672

Affiliated Companies
 
37,267

 
51,744

Long-term Debt Due Within One Year – Nonaffiliated
 
150,437

 
427

Risk Management Liabilities
 
70

 
918

Customer Deposits
 
50,147

 
48,700

Accrued Taxes
 
36,637

 
20,887

Accrued Interest
 
15,499

 
12,699

Regulatory Liability for Over-Recovered Fuel Costs
 
41,175

 

Other Current Liabilities
 
56,255

 
58,878

TOTAL CURRENT LIABILITIES
 
486,264

 
441,174

 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
Long-term Debt – Nonaffiliated
 
1,140,536

 
1,040,609

Long-term Risk Management Liabilities
 
8

 

Deferred Income Taxes
 
958,168

 
898,352

Regulatory Liabilities and Deferred Investment Tax Credits
 
339,161

 
334,479

Asset Retirement Obligations
 
42,680

 
37,030

Employee Benefits and Pension Obligations
 
16,456

 
20,095

Deferred Credits and Other Noncurrent Liabilities
 
18,285

 
13,589

TOTAL NONCURRENT LIABILITIES
 
2,515,294

 
2,344,154

 
 
 
 
 
TOTAL LIABILITIES
 
3,001,558

 
2,785,328

 
 
 
 
 
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
 
587,527

 
502,005

Accumulated Other Comprehensive Income (Loss)
 
4,374

 
4,943

TOTAL COMMON SHAREHOLDER’S EQUITY
 
1,113,168

 
1,028,215

 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
4,114,726

 
$
3,813,543

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

162



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
Nine Months Ended September 30,
 
 
2015
 
2014
OPERATING ACTIVITIES
 
 

 
 

Net Income
 
$
85,522

 
$
75,983

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

 
 

Depreciation and Amortization
 
90,148

 
73,085

Deferred Income Taxes
 
40,052

 
27,327

Allowance for Equity Funds Used During Construction
 
(5,952
)
 
(2,215
)
Mark-to-Market of Risk Management Contracts
 
(1,875
)
 
432

Pension Contributions to Qualified Plan Trust
 
(5,795
)
 
(4,439
)
Property Taxes
 
(8,049
)
 
(7,970
)
Fuel Over/Under-Recovery, Net
 
76,874

 
(33,246
)
Change in Other Noncurrent Assets
 
(13,066
)
 
2,035

Change in Other Noncurrent Liabilities
 
7,733

 
(2,015
)
Changes in Certain Components of Working Capital:
 
 

 
 

Accounts Receivable, Net
 
(2,646
)
 
333

Fuel, Materials and Supplies
 
(1,067
)
 
5,755

Accounts Payable
 
(9,339
)
 
(28,643
)
Accrued Taxes, Net
 
21,026

 
32,131

Other Current Assets
 
(1,866
)
 
(4,034
)
Other Current Liabilities
 
7,977

 
17,024

Net Cash Flows from Operating Activities
 
279,677

 
151,543

 
 
 
 
 
INVESTING ACTIVITIES
 
 

 
 

Construction Expenditures
 
(262,887
)
 
(256,741
)
Change in Advances to Affiliates, Net
 
(116,345
)
 

Other Investing Activities
 
7,679

 
2,881

Net Cash Flows Used for Investing Activities
 
(371,553
)
 
(253,860
)
 
 
 
 
 
FINANCING ACTIVITIES
 
 

 
 

Issuance of Long-term Debt – Nonaffiliated
 
248,785

 
74,973

Change in Advances from Affiliates, Net
 
(154,249
)
 
64,095

Retirement of Long-term Debt – Nonaffiliated
 
(319
)
 
(34,010
)
Principal Payments for Capital Lease Obligations
 
(2,765
)
 
(2,785
)
Other Financing Activities
 
735

 
595

Net Cash Flows from Financing Activities
 
92,187

 
102,868

 
 
 
 
 
Net Increase in Cash and Cash Equivalents
 
311

 
551

Cash and Cash Equivalents at Beginning of Period
 
1,352

 
1,277

Cash and Cash Equivalents at End of Period
 
$
1,663

 
$
1,828

 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 

 
 

Cash Paid for Interest, Net of Capitalized Amounts
 
$
40,562

 
$
37,458

Net Cash Paid (Received) for Income Taxes
 
12,772

 
(416
)
Noncash Acquisitions Under Capital Leases
 
1,546

 
2,098

Construction Expenditures Included in Current Liabilities as of September 30,
 
37,328

 
33,527

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

163



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
Property, Plant and Equipment
Disposition Plant Severance

164





SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED


165



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 was 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 SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013. The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million, primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, 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.  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 purchased power agreement attributable to Louisiana customers.  In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2015 Louisiana Formula Rate Filing

In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC.  The filing included a $14 million annual increase, which was effective August 2015.  This increase is subject to LPSC staff review and is subject to refund.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


166



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 2024 for Welsh Plant, Units 1 and 3 will cost approximately $700 million, excluding AFUDC.  As of September 30, 2015, SWEPCo has incurred costs of $303 million, including AFUDC, and has remaining contractual construction obligations of $62 million related to these projects.  SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. See "Mercury and Other Hazardous Air Pollutants (HAPs) Regulation" and "Climate Change, CO2 Regulation and Energy Policy" sections of “Environmental Issues” within “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries”. As of September 30, 2015, the net book value of Welsh Plant, Units 1 and 3 was $529 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. 

Merchant Portion of Turk Plant

SWEPCo constructed the Turk Plant, a base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012 and is included in the Vertically Integrated Utilities segment. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This share of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under cost-based rate recovery in Texas, Louisiana, and through SWEPCo’s wholesale customers under FERC-based rates.

If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

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 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in the 2014 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 179. 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 256 for additional discussion of relevant factors.


167



RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions of KWhs)
Retail:
 

 
 

 
 

 
 

Residential
2,087

 
1,949

 
5,135

 
4,974

Commercial
1,782

 
1,744

 
4,705

 
4,583

Industrial
1,419

 
1,511

 
4,079

 
4,453

Miscellaneous
19

 
20

 
60

 
60

Total Retail
5,307

 
5,224

 
13,979

 
14,070

 
 
 
 
 
 
 
 
Wholesale
2,460

 
2,458

 
7,092

 
7,022

 
 
 
 
 
 
 
 
Total KWhs
7,767

 
7,682

 
21,071

 
21,092


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,
 
2015
 
2014
 
2015
 
2014
 
(in degree days)
Actual - Heating (a)

 

 
920

 
1,039

Normal - Heating (b)
1

 
1

 
733

 
748

 
 
 
 
 
 
 
 
Actual - Cooling (c)
1,500

 
1,232

 
2,278

 
1,917

Normal - Cooling (b)
1,408

 
1,404

 
2,175

 
2,162


(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.


168



Third Quarter of 2015 Compared to Third Quarter of 2014
Reconciliation of Third Quarter of 2014 to Third Quarter of 2015
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
 
 
 
Third Quarter of 2014
 
$
73

 
 
 

Changes in Gross Margin:
 
 

Retail Margins (a)
 
28

Off-system Sales
 
(3
)
Transmission Revenues
 
4

Other Revenues
 
(1
)
Total Change in Gross Margin
 
28

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(17
)
Depreciation and Amortization
 
(2
)
Taxes Other Than Income Taxes
 
(1
)
Allowance for Equity Funds Used During Construction
 
4

Interest Expense
 
2

Total Change in Expenses and Other
 
(14
)
 
 
 

Income Tax Expense
 
(6
)
 
 
 

Third Quarter of 2015
 
$
81


(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 $28 million primarily due to the following:
A $25 million increase primarily due to revenue increases from rate riders in Louisiana and Texas.
A $16 million increase in weather-related usage primarily due to an 18% increase in cooling degree days.
These increases were partially offset by:
An $11 million decrease primarily due to lower weather-normalized retail sales.
Margins from Off-system Sales decreased $3 million primarily due to lower market prices and decreased sales volumes.
Transmission Revenues increased $4 million primarily due to higher SPP margins.

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

Other Operation and Maintenance expenses increased $17 million primarily due to the following:
A $7 million increase in transmission expenses primarily due to increased SPP transmission services.
A $3 million increase in general and administrative expenses.
A $3 million increase in generation plant expenses.
A $2 million increase in energy efficiency program expenses.
A $2 million increase in distribution expenses primarily due to increased vegetation management expenses.
Allowance for Equity Funds Used During Construction increased $4 million primarily due to increased environmental and transmission projects.
Income Tax Expense increased $6 million primarily due to an increase in pretax book income and by the recording of federal and state income tax adjustments, partially offset by the regulatory accounting treatment of state income taxes and by other book/tax differences which are accounted for on a flow-through basis.

169



Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
 
 
 
Nine Months Ended September 30, 2014
 
$
127

 
 
 

Changes in Gross Margin:
 
 

Retail Margins (a)
 
96

Off-system Sales
 
(8
)
Transmission Revenues
 
4

Other Revenues
 
(2
)
Total Change in Gross Margin
 
90

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(15
)
Depreciation and Amortization
 
(5
)
Taxes Other Than Income Taxes
 
(3
)
Interest Income
 
1

Allowance For Equity Funds Used During Construction
 
11

Interest Expense
 
4

Total Change in Expenses and Other
 
(7
)
 
 
 

Income Tax Expense
 
(25
)
 
 
 

Nine Months Ended September 30, 2015
 
$
185


(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 $96 million primarily due to the following:
A $45 million increase primarily due to revenue increases from rate riders in Louisiana and Texas.
A $26 million increase in municipal and cooperative revenues primarily due to formula rate adjustments.
A $22 million net increase in weather-related usage primarily due to a 16% increase in cooling degree days, partially offset by a decrease in heating degree days.
A $16 million increase primarily due to higher fuel cost recovery.
These increases were partially offset by:
A $13 million decrease primarily due to lower weather-normalized retail sales.
Margins from Off-system Sales decreased $8 million primarily due to lower market prices.
Transmission Revenues increased $4 million primarily due to higher SPP margins.
 
Expenses and Other and Income Tax Expense changed between years as follows:

Other Operation and Maintenance expenses increased $15 million primarily due to the following:
An $8 million increase in SPP transmission services.
A $7 million increase in distribution expenses primarily due to increased vegetation management expenses.
Depreciation and Amortization expenses increased $5 million primarily due to a higher depreciable base.
Allowance for Equity Funds Used During Construction increased $11 million primarily due to increased environmental and transmission projects.

170



Interest Expense decreased $4 million primarily due to the following:
A $6 million increase in the debt component of AFUDC due to increased environmental and transmission projects.
This decrease was partially offset by:
A $4 million increase due to increased long-term debt outstanding.
Income Tax Expense increased $25 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 2014 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 256 for a discussion of accounting pronouncements.

171




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
REVENUES
 
 
 
 
 
 
 
 

Electric Generation, Transmission and Distribution
 
$
525,922

 
$
526,047

 
$
1,387,644

 
$
1,397,326

Sales to AEP Affiliates
 
5,959

 
5,203

 
13,115

 
22,748

Other Revenues
 
618

 
521

 
1,486

 
1,570

TOTAL REVENUES
 
532,499

 
531,771

 
1,402,245

 
1,421,644

 
 
 
 
 
 
 
 
 
EXPENSES
 
 

 
 

 
 

 
 

Fuel and Other Consumables Used for Electric Generation
 
179,995

 
194,175

 
463,092

 
500,878

Purchased Electricity for Resale
 
23,597

 
36,960

 
70,799

 
138,380

Purchased Electricity from AEP Affiliates
 

 

 

 
3,766

Other Operation
 
81,391

 
68,601

 
214,835

 
206,442

Maintenance
 
34,425

 
29,867

 
100,076

 
93,946

Depreciation and Amortization
 
48,862

 
46,791

 
143,780

 
138,316

Taxes Other Than Income Taxes
 
23,014

 
22,246

 
66,062

 
63,272

TOTAL EXPENSES
 
391,284

 
398,640

 
1,058,644

 
1,145,000

 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
141,215

 
133,131

 
343,601

 
276,644

 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 

 
 

 
 

 
 

Interest Income
 
69

 
230

 
1,233

 
322

Allowance for Equity Funds Used During Construction
 
7,053

 
3,137

 
18,164

 
7,415

Interest Expense
 
(29,263
)
 
(31,644
)
 
(91,423
)
 
(95,258
)
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
 
119,074

 
104,854

 
271,575

 
189,123

 
 
 
 
 
 
 
 
 
Income Tax Expense
 
37,358

 
31,042

 
85,417

 
60,252

Equity Earnings of Unconsolidated Subsidiary
 
410

 
735

 
2,131

 
1,461

 
 
 
 
 
 
 
 
 
NET INCOME
 
82,126

 
74,547

 
188,289

 
130,332

 
 
 
 
 
 
 
 
 
Net Income Attributable to Noncontrolling Interest
 
1,013

 
1,109

 
3,002

 
3,337

 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER
 
$
81,113

 
$
73,438

 
$
185,287

 
$
126,995

The common stock of SWEPCo is wholly-owned by AEP.
 
 
 
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

172



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Net Income
$
82,126

 
$
74,547

 
$
188,289

 
$
130,332

 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
 

 
 

 
 

 
 

Cash Flow Hedges, Net of Tax of $232 and $305 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $843 and $881 for the Nine Months Ended September 30, 2015 and 2014, Respectively
432

 
567

 
1,566

 
1,636

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $129 and $126 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $387 and $379 for the Nine Months Ended September 30, 2015 and 2014, Respectively
(240
)
 
(235
)
 
(719
)
 
(704
)
 
 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE INCOME
192

 
332

 
847

 
932

 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
82,318

 
74,879

 
189,136

 
131,264

 
 
 
 
 
 
 
 
Total Comprehensive Income Attributable to Noncontrolling Interest
1,013

 
1,109

 
3,002

 
3,337

 
 

 
 

 
 

 
 

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER
$
81,305

 
$
73,770

 
$
186,134

 
$
127,927

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

173



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 2015 and 2014
(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, 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

 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY - DECEMBER 31, 2014
$
135,660

 
$
674,606

 
$
1,293,986

 
$
(7,466
)
 
$
415

 
$
2,097,201

 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 

 
 

 
(90,000
)
 
 

 
 

 
(90,000
)
Common Stock Dividends – Nonaffiliated
 

 
 

 
 

 
 

 
(3,099
)
 
(3,099
)
Net Income
 

 
 

 
185,287

 
 

 
3,002

 
188,289

Other Comprehensive Income
 

 
 

 
 

 
847

 
 

 
847

Contribution of Mutual Energy SWEPCo, LLC from Parent
 
 
1,945

 


 
 
 
 
 
1,945

TOTAL EQUITY - SEPTEMBER 30, 2015
$
135,660

 
$
676,551

 
$
1,389,273

 
$
(6,619
)
 
$
318

 
$
2,195,183

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

174



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2015 and December 31, 2014
(in thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2015
 
2014
CURRENT ASSETS
 
 
 
 
Cash and Cash Equivalents
(September 30, 2015 and December 31, 2014 Amounts Include $11,693 and $12,695, Respectively, Related to Sabine)
 
$
14,258

 
$
14,356

Advances to Affiliates
 
45,019

 
41,033

Accounts Receivable:
 
 
 
 
Customers
 
41,086

 
46,738

Affiliated Companies
 
33,937

 
37,114

Miscellaneous
 
31,322

 
25,625

Allowance for Uncollectible Accounts
 
(148
)
 
(516
)
Total Accounts Receivable
 
106,197

 
108,961

Fuel
(September 30, 2015 and December 31, 2014 Amounts Include $27,194 and $38,920, Respectively, Related to Sabine)
 
93,125

 
116,955

Materials and Supplies
 
72,735

 
73,666

Risk Management Assets
 
1,280

 
31

Deferred Income Tax Benefits
 
7,406

 
9,041

Accrued Tax Benefits
 
1,413

 
15,408

Regulatory Asset for Under-Recovered Fuel Costs
 
14,352

 
24,024

Prepayments and Other Current Assets
 
20,083

 
25,779

TOTAL CURRENT ASSETS
 
375,868

 
429,254

 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
Electric:
 
 
 
 
Generation
 
3,928,939

 
3,864,543

Transmission
 
1,362,543

 
1,300,729

Distribution
 
1,945,074

 
1,894,572

Other Property, Plant and Equipment (Including Plant to be Retired)
(September 30, 2015 and December 31, 2014 Amounts Include $291,896 and $288,183, Respectively, Related to Sabine)
 
895,958

 
878,753

Construction Work in Progress
 
681,991

 
471,980

Total Property, Plant and Equipment
 
8,814,505

 
8,410,577

Accumulated Depreciation and Amortization
(September 30, 2015 and December 31, 2014 Amounts Include $153,400 and $142,983, Respectively, Related to Sabine)
 
2,611,129

 
2,503,290

TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
6,203,376

 
5,907,287

 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
Regulatory Assets
 
413,434

 
393,602

Employee Benefits and Pension Assets
 
23,437

 
21,427

Deferred Charges and Other Noncurrent Assets
 
85,491

 
65,323

TOTAL OTHER NONCURRENT ASSETS
 
522,362

 
480,352

 
 
 
 
 
TOTAL ASSETS
 
$
7,101,606

 
$
6,816,893

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

175



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2015 and December 31, 2014
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2015
 
2014
 
 
(in thousands)
CURRENT LIABILITIES
 
 
 
 
Accounts Payable:
 
 
 
 
General
 
$
160,885

 
$
175,109

Affiliated Companies
 
58,866

 
67,410

Long-term Debt Due Within One Year – Nonaffiliated
 
3,250

 
306,750

Risk Management Liabilities
 
1,302

 
1,082

Customer Deposits
 
60,594

 
59,903

Accrued Taxes
 
83,125

 
43,965

Accrued Interest
 
23,097

 
44,328

Obligations Under Capital Leases
 
22,081

 
17,557

Other Current Liabilities
 
81,965

 
104,553

TOTAL CURRENT LIABILITIES
 
495,165

 
820,657

 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
Long-term Debt – Nonaffiliated
 
2,280,716

 
1,833,687

Long-term Risk Management Liabilities
 
757

 

Deferred Income Taxes
 
1,415,833

 
1,351,111

Regulatory Liabilities and Deferred Investment Tax Credits
 
457,438

 
458,530

Asset Retirement Obligations
 
108,093

 
92,015

Employee Benefits and Pension Obligations
 
26,224

 
25,374

Obligations Under Capital Leases
 
74,533

 
91,044

Deferred Credits and Other Noncurrent Liabilities
 
47,664

 
47,274

TOTAL NONCURRENT LIABILITIES
 
4,411,258

 
3,899,035

 
 
 
 
 
TOTAL LIABILITIES
 
4,906,423

 
4,719,692

 
 
 
 
 
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
 
676,551

 
674,606

Retained Earnings
 
1,389,273

 
1,293,986

Accumulated Other Comprehensive Income (Loss)
 
(6,619
)
 
(7,466
)
TOTAL COMMON SHAREHOLDER’S EQUITY
 
2,194,865

 
2,096,786

 
 
 
 
 
Noncontrolling Interest
 
318

 
415

 
 
 
 
 
TOTAL EQUITY
 
2,195,183

 
2,097,201

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 
$
7,101,606

 
$
6,816,893

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

176



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
 
 
Nine Months Ended September 30,
 
 
2015
 
2014
OPERATING ACTIVITIES
 
 

 
 

Net Income
 
$
188,289

 
$
130,332

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
 
Depreciation and Amortization
 
143,780

 
138,316

Deferred Income Taxes
 
45,672

 
181,482

Allowance for Equity Funds Used During Construction
 
(18,164
)
 
(7,415
)
Mark-to-Market of Risk Management Contracts
 
(272
)
 
802

Pension Contributions to Qualified Plan Trust
 
(8,052
)
 
(3,832
)
Property Taxes
 
(13,024
)
 
(12,503
)
Fuel Over/Under-Recovery, Net
 
11,705

 
(19,547
)
Change in Other Noncurrent Assets
 
2,756

 
11,926

Change in Other Noncurrent Liabilities
 
(1,820
)
 
39

Changes in Certain Components of Working Capital:
 
 
 
 
Accounts Receivable, Net
 
2,764

 
36,622

Fuel, Materials and Supplies
 
24,761

 
22,500

Accounts Payable
 
(17,120
)
 
(15,046
)
Accrued Taxes, Net
 
53,155

 
(76,982
)
Accrued Interest
 
(21,231
)
 
(24,406
)
Other Current Assets
 
2,794

 
(7,448
)
Other Current Liabilities
 
(23,678
)
 
(2,983
)
Net Cash Flows from Operating Activities
 
372,315

 
351,857

 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
Construction Expenditures
 
(408,293
)
 
(351,666
)
Change in Advances to Affiliates, Net
 
(2,038
)
 

Other Investing Activities
 
4,427

 
4,334

Net Cash Flows Used for Investing Activities
 
(405,904
)
 
(347,332
)
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
445,949

 
99,633

Change in Advances from Affiliates, Net
 

 
(2,851
)
Retirement of Long-term Debt – Nonaffiliated
 
(306,750
)
 
(3,250
)
Principal Payments for Capital Lease Obligations
 
(13,398
)
 
(13,673
)
Dividends Paid on Common Stock
 
(90,000
)
 
(75,000
)
Dividends Paid on Common Stock – Nonaffiliated
 
(3,099
)
 
(3,483
)
Other Financing Activities
 
789

 
844

Net Cash Flows from Financing Activities
 
33,491

 
2,220

 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
(98
)
 
6,745

Cash and Cash Equivalents at Beginning of Period
 
14,356

 
17,241

Cash and Cash Equivalents at End of Period
 
$
14,258

 
$
23,986

 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
106,078

 
$
113,137

Net Cash Paid (Received) for Income Taxes
 
12,320

 
(13,820
)
Noncash Acquisitions Under Capital Leases
 
1,493

 
3,923

Construction Expenditures Included in Current Liabilities as of September 30,
 
85,268

 
88,291

Noncash Contribution of Mutual Energy SWEPCo, LLC from Parent
 
(1,945
)
 

Noncash Increase in Advances to Affiliates, Net due to Contribution of Mutual Energy SWEPCo, LLC
 
1,948

 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179.

177




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
Benefit Plans
Business Segments
Derivatives and Hedging
Fair Value Measurements
Income Taxes
Financing Activities
Variable Interest Entities
Property, Plant and Equipment
Disposition Plant Severance





178



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
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
Property, Plant and Equipment
APCo, I&M, OPCo, PSO, SWEPCo
Disposition Plant Severance
APCo, I&M, OPCo, PSO, SWEPCo


179



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, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 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 20, 2015.



180



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.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. There were no events requiring the application of this new accounting guidance.

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, determine 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 FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. 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, 2018.

ASU 2015-01 “Income Statement Extraordinary and Unusual Items” (ASU 2015-01)

In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. Management plans to adopt ASU 2015-01 effective January 1, 2016.

ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03)

In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The Registrant Subsidiaries include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt.

181



The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management intends to early adopt ASU 2015-03 for the 2015 Form 10-K.

ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05)

In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-05 effective January 1, 2016.

ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11)

In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-11 effective January 1, 2017.

ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13)

In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator.  Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception.  As a result, an entity may elect to designate that contract as a normal purchase or normal sale.

The new accounting guidance is effective upon issuance and applied prospectively.  Management has analyzed the impact of this new standard and determined that it will have no impact on the accounting of the Registrant Subsidiaries' contracts.  Additionally, adoption has no impact on net income.  Management adopted ASU 2015-13 upon its issuance date.

182



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, 2015 and 2014.  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, 2015
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2015
 
$

 
$
4,027

 
$
220

 
$
4,247

Change in Fair Value Recognized in AOCI
 

 

 

 

Amounts Reclassified from AOCI
 

 
(222
)
 
(458
)
 
(680
)
Net Current Period Other Comprehensive Loss
 

 
(222
)
 
(458
)
 
(680
)
Balance in AOCI as of September 30, 2015
 
$

 
$
3,805

 
$
(238
)
 
$
3,567


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 (Loss)
 

 
170

 
(333
)
 
(163
)
Balance in AOCI as of September 30, 2014
 
$

 
$
3,766

 
$
(1,232
)
 
$
2,534



183



APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2015
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2014
 
$

 
$
3,896

 
$
1,136

 
$
5,032

Change in Fair Value Recognized in AOCI
 

 

 

 

Amounts Reclassified from AOCI
 

 
(91
)
 
(1,374
)
 
(1,465
)
Net Current Period Other Comprehensive Loss
 

 
(91
)
 
(1,374
)
 
(1,465
)
Balance in AOCI as of September 30, 2015
 
$

 
$
3,805

 
$
(238
)
 
$
3,567


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 (Loss)
 
(94
)
 
676

 
(999
)
 
(417
)
Balance in AOCI as of September 30, 2014
 
$

 
$
3,766

 
$
(1,232
)
 
$
2,534



184



I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2015
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2015
 
$

 
$
(13,871
)
 
$
68

 
$
(13,803
)
Change in Fair Value Recognized in AOCI
 

 

 

 

Amounts Reclassified from AOCI
 

 
267

 
11

 
278

Net Current Period Other Comprehensive Income
 

 
267

 
11

 
278

Balance in AOCI as of September 30, 2015
 
$

 
$
(13,604
)
 
$
79

 
$
(13,525
)

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
)


185



I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2015
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2014
 
$

 
$
(14,406
)
 
$
46

 
$
(14,360
)
Change in Fair Value Recognized in AOCI
 

 

 

 

Amounts Reclassified from AOCI
 

 
802

 
33

 
835

Net Current Period Other Comprehensive Income
 

 
802

 
33

 
835

Balance in AOCI as of September 30, 2015
 
$

 
$
(13,604
)
 
$
79

 
$
(13,525
)

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 (Loss)
 
(46
)
 
1,231

 
128

 
1,313

Balance in AOCI as of September 30, 2014
 
$

 
$
(14,745
)
 
$
549

 
$
(14,196
)


186



OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2015
 
 
Cash Flow Hedges
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2015
 
$

 
$
4,916

 
$
4,916

Change in Fair Value Recognized in AOCI
 

 

 

Amounts Reclassified from AOCI
 

 
(344
)
 
(344
)
Net Current Period Other Comprehensive Loss
 

 
(344
)
 
(344
)
Balance in AOCI as of September 30, 2015
 
$

 
$
4,572

 
$
4,572

 
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
 
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 Loss
 

 
(343
)
 
(343
)
Balance in AOCI as of September 30, 2014
 
$

 
$
5,945

 
$
5,945



187



OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2015
 
 
Cash Flow Hedges
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2014
 
$

 
$
5,602

 
$
5,602

Change in Fair Value Recognized in AOCI
 

 

 

Amounts Reclassified from AOCI
 

 
(1,030
)
 
(1,030
)
Net Current Period Other Comprehensive Loss
 

 
(1,030
)
 
(1,030
)
Balance in AOCI as of September 30, 2015
 
$

 
$
4,572

 
$
4,572


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
 
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 Loss
 
(105
)
 
(1,029
)
 
(1,134
)
Balance in AOCI as of September 30, 2014
 
$

 
$
5,945

 
$
5,945



188



PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2015
 
 
Cash Flow Hedges
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2015
 
$

 
$
4,563

 
$
4,563

Change in Fair Value Recognized in AOCI
 

 

 

Amounts Reclassified from AOCI
 

 
(189
)
 
(189
)
Net Current Period Other Comprehensive Loss
 

 
(189
)
 
(189
)
Balance in AOCI as of September 30, 2015
 
$

 
$
4,374

 
$
4,374

 
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 Loss
 

 
(190
)
 
(190
)
Balance in AOCI as of September 30, 2014
 
$

 
$
5,132

 
$
5,132



189



PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2015
 
 
Cash Flow Hedges
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2014
 
$

 
$
4,943

 
$
4,943

Change in Fair Value Recognized in AOCI
 

 

 

Amounts Reclassified from AOCI
 

 
(569
)
 
(569
)
Net Current Period Other Comprehensive Loss
 

 
(569
)
 
(569
)
Balance in AOCI as of September 30, 2015
 
$

 
$
4,374

 
$
4,374


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 Loss
 
(57
)
 
(569
)
 
(626
)
Balance in AOCI as of September 30, 2014
 
$

 
$
5,132

 
$
5,132



190



SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2015
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of June 30, 2015
 
$

 
$
(9,902
)
 
$
3,091

 
$
(6,811
)
Change in Fair Value Recognized in AOCI
 

 

 

 

Amounts Reclassified from AOCI
 

 
432

 
(240
)
 
192

Net Current Period Other Comprehensive Income (Loss)
 

 
432

 
(240
)
 
192

Balance in AOCI as of September 30, 2015
 
$

 
$
(9,470
)
 
$
2,851

 
$
(6,619
)

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 (Loss)
 

 
567

 
(235
)
 
332

Balance in AOCI as of September 30, 2014
 
$

 
$
(11,602
)
 
$
4,090

 
$
(7,512
)


191



SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2015
 
 
Cash Flow Hedges
 
 
 
 
 
 
Commodity
 
Interest Rate and
Foreign Currency
 
Pension
and OPEB
 
Total
 
 
(in thousands)
Balance in AOCI as of December 31, 2014
 
$

 
$
(11,036
)
 
$
3,570

 
$
(7,466
)
Change in Fair Value Recognized in AOCI
 

 

 

 

Amounts Reclassified from AOCI
 

 
1,566

 
(719
)
 
847

Net Current Period Other Comprehensive Income (Loss)
 

 
1,566

 
(719
)
 
847

Balance in AOCI as of September 30, 2015
 
$

 
$
(9,470
)
 
$
2,851

 
$
(6,619
)

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 (Loss)
 
(66
)
 
1,702

 
(704
)
 
932

Balance in AOCI as of September 30, 2014
 
$

 
$
(11,602
)
 
$
4,090

 
$
(7,512
)


192



Reclassifications from Accumulated Other Comprehensive Income

The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2015 and 2014.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs.  See Note 6 for additional details.
 
APCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2015 and 2014
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Three Months Ended September 30,
 
 
2015
 
2014
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Purchased Electricity for Resale
 
$

 
$

Regulatory Assets/(Liabilities), Net (a)
 

 

Subtotal  Commodity
 

 

 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
(342
)
 
262

Subtotal  Interest Rate and Foreign Currency
 
(342
)
 
262

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(342
)
 
262

Income Tax (Expense) Credit
 
(120
)
 
92

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(222
)
 
170

 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 
(1,282
)
 
(1,281
)
Amortization of Actuarial (Gains)/Losses
 
577

 
769

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(705
)
 
(512
)
Income Tax (Expense) Credit
 
(247
)
 
(179
)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(458
)
 
(333
)
 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(680
)
 
$
(163
)


193



APCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2015 and 2014
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Nine Months Ended September 30,
 
 
2015
 
2014
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Purchased Electricity for Resale
 
$

 
$
(526
)
Other Operation Expense
 

 
(10
)
Maintenance Expense
 

 
(20
)
Property, Plant and Equipment
 

 
(17
)
Regulatory Assets/(Liabilities), Net (a)
 

 
(2,165
)
Subtotal  Commodity
 

 
(2,738
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
(140
)
 
1,042

Subtotal  Interest Rate and Foreign Currency
 
(140
)
 
1,042

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(140
)
 
(1,696
)
Income Tax (Expense) Credit
 
(49
)
 
(592
)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(91
)
 
(1,104
)
 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 
(3,847
)
 
(3,846
)
Amortization of Actuarial (Gains)/Losses
 
1,733

 
2,309

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(2,114
)
 
(1,537
)
Income Tax (Expense) Credit
 
(740
)
 
(538
)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(1,374
)
 
(999
)
 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(1,465
)
 
$
(2,103
)


194



I&M

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2015 and 2014
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Three Months Ended September 30,
 
 
2015
 
2014
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Purchased Electricity for Resale
 
$

 
$

Regulatory Assets/(Liabilities), Net (a)
 

 

Subtotal  Commodity
 

 

 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
412

 
631

Subtotal  Interest Rate and Foreign Currency
 
412

 
631

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
412

 
631

Income Tax (Expense) Credit
 
145

 
221

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
267

 
410

 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 
(198
)
 
(200
)
Amortization of Actuarial (Gains)/Losses
 
215

 
264

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
17

 
64

Income Tax (Expense) Credit
 
6

 
22

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
11

 
42

 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
278

 
$
452



195



I&M

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2015 and 2014
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Nine Months Ended September 30,
 
 
2015
 
2014
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Purchased Electricity for Resale
 
$

 
$
(812
)
Other Operation Expense
 

 
(7
)
Maintenance Expense
 

 
(7
)
Property, Plant and Equipment
 

 
(10
)
Regulatory Assets/(Liabilities), Net (a)
 

 
(973
)
Subtotal  Commodity
 

 
(1,809
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
1,234

 
1,893

Subtotal  Interest Rate and Foreign Currency
 
1,234

 
1,893

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
1,234

 
84

Income Tax (Expense) Credit
 
432

 
29

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
802

 
55

 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 
(596
)
 
(597
)
Amortization of Actuarial (Gains)/Losses
 
647

 
791

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
51

 
194

Income Tax (Expense) Credit
 
18

 
66

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
33

 
128

 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
835

 
$
183



196



OPCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2015 and 2014
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Three Months Ended September 30,
 
 
2015
 
2014
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Other Operation Expense
 
$

 
$

Maintenance Expense
 

 

Property, Plant and Equipment
 

 

Regulatory Assets/(Liabilities), Net (a)
 

 

Subtotal – Commodity
 

 

 
 
 
 
 
Interest Rate and Foreign Currency:
 
 

 
 
Depreciation and Amortization Expense
 
(4
)
 
(3
)
Interest Expense
 
(526
)
 
(524
)
Subtotal  Interest Rate and Foreign Currency
 
(530
)
 
(527
)
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(530
)
 
(527
)
Income Tax (Expense) Credit
 
(186
)
 
(184
)
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(344
)
 
$
(343
)

OPCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2015 and 2014
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Nine Months Ended September 30,
 
 
2015
 
2014
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Other Operation Expense
 
$

 
$
(11
)
Maintenance Expense
 

 
(11
)
Property, Plant and Equipment
 

 
(18
)
Regulatory Assets/(Liabilities), Net (a)
 

 
(122
)
Subtotal  Commodity
 

 
(162
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Depreciation and Amortization Expense
 
(10
)
 
(9
)
Interest Expense
 
(1,574
)
 
(1,572
)
Subtotal  Interest Rate and Foreign Currency
 
(1,584
)
 
(1,581
)
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(1,584
)
 
(1,743
)
Income Tax (Expense) Credit
 
(554
)
 
(609
)
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(1,030
)
 
$
(1,134
)


197



PSO

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2015 and 2014
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Three Months Ended September 30,
 
 
2015
 
2014
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 
 
 
Other Operation Expense
 
$

 
$

Maintenance Expense
 

 

Property, Plant and Equipment
 

 

Regulatory Assets/(Liabilities), Net (a)
 

 

Subtotal  Commodity
 

 

 
 
 
 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
(291
)
 
(292
)
Subtotal  Interest Rate and Foreign Currency
 
(291
)
 
(292
)
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(291
)
 
(292
)
Income Tax (Expense) Credit
 
(102
)
 
(102
)
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(189
)
 
$
(190
)
 
PSO

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2015 and 2014
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Nine Months Ended September 30,
 
 
2015
 
2014
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Other Operation Expense
 
$

 
$
(8
)
Maintenance Expense
 

 
(9
)
Property, Plant and Equipment
 

 
(13
)
Regulatory Assets/(Liabilities), Net (a)
 

 
(58
)
Subtotal  Commodity
 

 
(88
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
(875
)
 
(876
)
Subtotal  Interest Rate and Foreign Currency
 
(875
)
 
(876
)
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(875
)
 
(964
)
Income Tax (Expense) Credit
 
(306
)
 
(338
)
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
(569
)
 
$
(626
)


198



SWEPCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2015 and 2014
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Three Months Ended September 30,
 
 
2015
 
2014
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Other Operation Expense
 
$

 
$

Maintenance Expense
 

 

Property, Plant and Equipment
 

 

Regulatory Assets/(Liabilities), Net (a)
 

 

Subtotal  Commodity
 

 

 
 
 
 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
665

 
872

Subtotal  Interest Rate and Foreign Currency
 
665

 
872

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
665

 
872

Income Tax (Expense) Credit
 
233

 
305

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
432

 
567

 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 
(468
)
 
(478
)
Amortization of Actuarial (Gains)/Losses
 
99

 
118

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(369
)
 
(360
)
Income Tax (Expense) Credit
 
(129
)
 
(125
)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(240
)
 
(235
)
 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
192

 
$
332

 

199



SWEPCo

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2015 and 2014
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Nine Months Ended September 30,
 
 
2015
 
2014
Gains and Losses on Cash Flow Hedges
 
(in thousands)
Commodity:
 
 

 
 
Other Operation Expense
 
$

 
$
(13
)
Maintenance Expense
 

 
(10
)
Property, Plant and Equipment
 

 
(11
)
Regulatory Assets/(Liabilities), Net (a)
 

 
(67
)
Subtotal  Commodity
 

 
(101
)
 
 
 

 
 
Interest Rate and Foreign Currency:
 
 

 
 
Interest Expense
 
2,409

 
2,616

Subtotal  Interest Rate and Foreign Currency
 
2,409

 
2,616

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
2,409

 
2,515

Income Tax (Expense) Credit
 
843

 
879

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
1,566

 
1,636

 
 
 
 
 
Pension and OPEB
 
 

 
 
Amortization of Prior Service Cost (Credit)
 
(1,402
)
 
(1,433
)
Amortization of Actuarial (Gains)/Losses
 
296

 
351

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
(1,106
)
 
(1,082
)
Income Tax (Expense) Credit
 
(387
)
 
(378
)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
(719
)
 
(704
)
 
 
 

 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
847

 
$
932

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


200



4.  RATE MATTERS

As discussed in the 2014 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 2014 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 2015 and updates the 2014 Annual Report.

Regulatory Assets Pending Final Regulatory Approval
 
 
APCo
 
 
September 30,
 
December 31,
 
 
2015
 
2014
Noncurrent Regulatory Assets
 
(in thousands)
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
Materials and Supplies Related to Retired Plants
 
$
8,592

 
$

Vegetation Management Program  West Virginia
 

 
19,089

Regulatory Assets Currently Not Earning a Return
 
 
 
 
Asset Retirement Obligation Costs Related to Retired Plants
 
32,128

 

Peak Demand Reduction/Energy Efficiency – Virginia
 
11,650

 
8,791

Amos Plant Transfer Costs – West Virginia
 
1,950

 
1,377

Deferred Permit Fees Related to Retired Plants – West Virginia
 
617

 

Storm Related Costs  West Virginia
 

 
65,206

Carbon Capture and Storage Product Validation Facility – West Virginia, FERC
 

 
13,264

IGCC Pre-Construction Costs  West Virginia, FERC
 

 
10,838

Expanded Net Energy Charge  Coal Inventory – West Virginia
 

 
3,421

Expanded Net Energy Charge  Construction Surcharge – West Virginia
 

 
2,307

Carbon Capture and Storage Commercial Scale Facility  West Virginia, FERC
 

 
1,287

Other Regulatory Assets Pending Final Regulatory Approval
 

 
168

Total Regulatory Assets Pending Final Regulatory Approval
 
$
54,937

 
$
125,748

 
 
I&M
 
 
September 30,
 
December 31,
 
 
2015
 
2014
Noncurrent Regulatory Assets
 
(in thousands)
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
Materials and Supplies Related to Retired Plants
 
$
11,652

 
$

Regulatory Assets Currently Not Earning a Return
 
 
 
 
Asset Retirement Obligation Costs Related to Retired Plants
 
27,079

 

Cook Plant Turbine
 
8,955

 
6,596

Stranded Costs on Abandoned Plants
 
3,897

 
3,897

Deferred Cook Plant Life Cycle Management Project Costs  Michigan
 
3,445

 
1,222

Rockport Dry Sorbent Injection System
 
1,865

 
148

Storm Related Costs  Indiana
 

 
1,074

Other Regulatory Assets Pending Final Regulatory Approval
 
11

 
712

Total Regulatory Assets Pending Final Regulatory Approval
 
$
56,904

 
$
13,649


201



 
 
OPCo
 
 
September 30,
 
December 31,
 
 
2015
 
2014
Noncurrent Regulatory Assets
 
(in thousands)
 
 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 

 
 

Ormet Special Rate Recovery Mechanism
 
$
10,483

 
$
10,483

Total Regulatory Assets Pending Final Regulatory Approval
 
$
10,483

 
$
10,483

 
 
PSO
 
 
September 30,
 
December 31,
 
 
2015
 
2014
Noncurrent Regulatory Assets
 
(in thousands)
 
 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 

 
 

Storm Related Costs
 
$

 
$
16,614

Other Regulatory Assets Pending Final Regulatory Approval
 

 
1,079

Total Regulatory Assets Pending Final Regulatory Approval
 
$

 
$
17,693

 
 
SWEPCo
 
 
September 30,
 
December 31,
 
 
2015
 
2014
Noncurrent Regulatory Assets
 
(in thousands)
 
 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
Shipe Road Transmission Project
 
$
3,031

 
$
2,287

Asset Retirement Obligation
 
1,516

 
1,144

Rate Case Expenses
 

 
8,126

Other Regulatory Assets Pending Final Regulatory Approval
 
695

 
558

Total Regulatory Assets Pending Final Regulatory Approval
 
$
5,242

 
$
12,115


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. 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.

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 appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. In September 2015, the Supreme Court of Ohio denied the IEU's request for reconsideration and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate.


202



June 2012 – May 2015 ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that established 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 $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, which has scheduled oral arguments for the fourth quarter of 2015.

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 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 2015, the PUCO issued an order that approved, with modifications, OPCo's July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00/MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million. In May 2015, the PUCO granted intervenors requests for rehearing. As of September 30, 2015, OPCo's net deferred capacity costs balance of $392 million, including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. Through September 30, 2015, OPCo has collected $183 million in deferred capacity costs, and related carrying charges.

In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. 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 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015.

In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. 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.

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 October 2014, the independent auditor, selected by the PUCO, 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/MW day capacity charge, the independent auditor has recommended 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 disagrees with the findings in the audit report.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.


203



June 2015 - May 2018 ESP Including PPA Application

In December 2013, OPCo filed an application with the PUCO to approve an ESP that included 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 also included 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 PPA. 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 February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo's and various intervenors' requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider.

In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. A hearing at the PUCO related to the PPA commenced in September 2015. In October 2015, the PUCO staff submitted testimony that opposed the PPA application as currently proposed but concluded that, with changes, a PPA could be in the public interest.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, 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 June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements.

Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation and 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.


204



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 September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. 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.

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 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (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, 2015, 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.


205



SWEPCo Rate Matters

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 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, 2015, the net book value of Welsh Plant, Unit 2 was $83 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 was 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 and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, 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 SWEPCo's 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 review base rates in 2014 and 2015 and that SWEPCo recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million, primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, 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.  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 purchased power agreement attributable to Louisiana customers.  In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


206



2015 Louisiana Formula Rate Filing

In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC.  The filing included a $14 million annual increase, which was effective August 2015.  This increase is subject to LPSC staff review and is subject to refund.  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 2024 for Welsh Plant, Units 1 and 3 will cost approximately $700 million, excluding AFUDC.  As of September 30, 2015, SWEPCo has incurred costs of $303 million, including AFUDC, and has remaining contractual construction obligations of $62 million related to these projects.  SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of September 30, 2015, the net book value of Welsh Plant, Units 1 and 3 was $529 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

2014 West Virginia Base Rate Case

In May 2015, the WVPSC issued an order on APCo's base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $85 million based upon a 9.75% return on common equity. The order included a delayed billing of $22 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $22 million delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $38 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $77 million in previously recorded regulatory assets, which will predominantly be recovered over five years.

2015 Virginia Regulatory Asset Proceeding

In January 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets. In February and March 2015, briefs related to this proceeding were filed by various parties. As of September 30, 2015, APCo’s authorized regulatory assets under review in this proceeding were $11 million. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition.

New Virginia Legislation Affecting Biennial Reviews

In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA.


207



PSO Rate Matters

2015 Oklahoma Base Rate Case

In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million, which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million, excluding AFUDC. As of September 30, 2015, PSO has incurred costs of $162 million related to these projects, including AFUDC.

In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million, will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of September 30, 2015, the net book value of Northeastern Plant, Unit 4 was $94 million, before cost of removal, including materials and supplies inventory and CWIP.

In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million, based upon returns on common equity ranging from 8.75% to 9.3%, and increases to depreciation expense ranging from $23 million to $46 million. Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certain intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC are scheduled for December 2015.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
  
2014 Oklahoma Base Rate Case

In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for 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 provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) 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 and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014.


208



I&M Rate Matters

Tanners Creek Plant

In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon 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. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates.

In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval.

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 for eligible transmission, distribution and storage system improvements totaling $787 million. In April 2015, I&M filed a notice with the IURC to exclude $117 million related to certain projects. In September 2015, the IURC granted I&M's motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals.

209



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. Contingent liabilities are accrued only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When determined that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, such contingencies and the possible loss or range of loss are disclosed if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.
 
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 2014 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, 2015, the maximum future payment for letters of credit issued under the revolving credit facilities was as follows:
Company
 
Amount
 
Maturity
 
 
(in thousands)
 
 
I&M
 
$
35

 
March 2016

AEP issues letters of credit under two uncommitted facilities totaling $150 million.  An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility.  As of September 30, 2015, the maximum future payment for letters of credit issued under the uncommitted facilities was as follows:
Company
 
Amount
 
Maturity
 
 
(in thousands)
 
 
OPCo
 
$
4,200

 
September 2016

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 2017


210



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 $58 million.  Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation.  As of September 30, 2015, SWEPCo has collected $65 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 $49 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed balance sheets.

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

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

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of September 30, 2015, 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 AEP companies related to power purchase and sale activity.  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.

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, 2015, 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
 
$
5,396

I&M
 
3,448

OPCo
 
6,075

PSO
 
2,785

SWEPCo
 
3,086



211



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 $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2015.

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 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 $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, management believes that the fair value would produce a sufficient sales price to avoid any loss.

ENVIRONMENTAL CONTINGENCIES

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

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

In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M started remediation work in accordance with a plan approved by MDEQ.  In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of September 30, 2015, I&M's accrual for all of these sites is approximately $8 million.  As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the 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.


212



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. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing.  In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. Plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. Management will continue to defend against the remaining claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Wage and Hours Lawsuit – Affecting PSO

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

In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action.  Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. Management will continue to defend the case. Management does not believe a loss is probable. If there is an unfavorable outcome contrary to expectations, management estimates possible losses of up to $30 million.

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.  In August 2015, the court denied the motion. Management appealed that decision to the West Virginia Supreme Court. Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

213



6.  BENEFIT PLANS

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

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2015 and 2014:

APCo
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2015

2014
 
2015
 
2014
 
(in thousands)
Service Cost
$
2,175

 
$
1,759

 
$
286

 
$
362

Interest Cost
6,679

 
7,406

 
2,584

 
3,197

Expected Return on Plan Assets
(8,745
)
 
(8,482
)
 
(4,529
)
 
(4,634
)
Amortization of Prior Service Cost (Credit)
45

 
49

 
(2,513
)
 
(2,512
)
Amortization of Net Actuarial Loss
3,474

 
4,149

 
900

 
1,145

Net Periodic Benefit Cost (Credit)
$
3,628

 
$
4,881

 
$
(3,272
)
 
$
(2,442
)
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Service Cost
$
6,525

 
$
5,277

 
$
857

 
$
1,086

Interest Cost
20,037

 
22,218

 
7,753

 
9,591

Expected Return on Plan Assets
(26,236
)
 
(25,445
)
 
(13,587
)
 
(13,900
)
Amortization of Prior Service Cost (Credit)
135

 
148

 
(7,538
)
 
(7,537
)
Amortization of Net Actuarial Loss
10,421

 
12,445

 
2,699

 
3,436

Net Periodic Benefit Cost (Credit)
$
10,882

 
$
14,643

 
$
(9,816
)
 
$
(7,324
)


214



I&M
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Service Cost
$
3,217

 
$
2,517

 
$
406

 
$
486

Interest Cost
6,114

 
6,573

 
1,592

 
1,909

Expected Return on Plan Assets
(8,115
)
 
(7,749
)
 
(3,304
)
 
(3,363
)
Amortization of Prior Service Cost (Credit)
45

 
49

 
(2,355
)
 
(2,355
)
Amortization of Net Actuarial Loss
3,145

 
3,647

 
506

 
592

Net Periodic Benefit Cost (Credit)
$
4,406

 
$
5,037

 
$
(3,155
)
 
$
(2,731
)
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Service Cost
$
9,651

 
$
7,551

 
$
1,219

 
$
1,460

Interest Cost
18,344

 
19,720

 
4,776

 
5,728

Expected Return on Plan Assets
(24,347
)
 
(23,245
)
 
(9,912
)
 
(10,090
)
Amortization of Prior Service Cost (Credit)
136

 
146

 
(7,066
)
 
(7,066
)
Amortization of Net Actuarial Loss
9,434

 
10,939

 
1,519

 
1,776

Net Periodic Benefit Cost (Credit)
$
13,218

 
$
15,111

 
$
(9,464
)
 
$
(8,192
)

OPCo
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Service Cost
$
1,671

 
$
1,285

 
$
216

 
$
256

Interest Cost
5,071

 
5,527

 
1,615

 
1,900

Expected Return on Plan Assets
(6,878
)
 
(6,607
)
 
(3,376
)
 
(3,379
)
Amortization of Prior Service Cost (Credit)
35

 
40

 
(1,731
)
 
(1,731
)
Amortization of Net Actuarial Loss
2,644

 
3,105

 
517

 
595

Net Periodic Benefit Cost (Credit)
$
2,543

 
$
3,350

 
$
(2,759
)
 
$
(2,359
)
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Service Cost
$
5,015

 
$
3,855

 
$
647

 
$
769

Interest Cost
15,211

 
16,579

 
4,845

 
5,701

Expected Return on Plan Assets
(20,634
)
 
(19,820
)
 
(10,130
)
 
(10,139
)
Amortization of Prior Service Cost (Credit)
105

 
118

 
(5,192
)
 
(5,192
)
Amortization of Net Actuarial Loss
7,932

 
9,316

 
1,552

 
1,785

Net Periodic Benefit Cost (Credit)
$
7,629

 
$
10,048

 
$
(8,278
)
 
$
(7,076
)


215



PSO
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Service Cost
$
1,598

 
$
1,301

 
$
170

 
$
209

Interest Cost
2,731

 
3,015

 
759

 
893

Expected Return on Plan Assets
(3,786
)
 
(3,651
)
 
(1,578
)
 
(1,575
)
Amortization of Prior Service Cost (Credit)
63

 
74

 
(1,072
)
 
(1,072
)
Amortization of Net Actuarial Loss
1,418

 
1,689

 
242

 
278

Net Periodic Benefit Cost (Credit)
$
2,024

 
$
2,428

 
$
(1,479
)
 
$
(1,267
)
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Service Cost
$
4,796

 
$
3,905

 
$
509

 
$
629

Interest Cost
8,194

 
9,043

 
2,277

 
2,680

Expected Return on Plan Assets
(11,358
)
 
(10,953
)
 
(4,732
)
 
(4,725
)
Amortization of Prior Service Cost (Credit)
189

 
222

 
(3,217
)
 
(3,217
)
Amortization of Net Actuarial Loss
4,252

 
5,065

 
725

 
832

Net Periodic Benefit Cost (Credit)
$
6,073

 
$
7,282

 
$
(4,438
)
 
$
(3,801
)

SWEPCo
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Service Cost
$
2,081

 
$
1,655

 
$
211

 
$
253

Interest Cost
2,932

 
3,163

 
837

 
998

Expected Return on Plan Assets
(4,008
)
 
(3,857
)
 
(1,735
)
 
(1,754
)
Amortization of Prior Service Cost (Credit)
78

 
87

 
(1,289
)
 
(1,289
)
Amortization of Net Actuarial Loss
1,506

 
1,762

 
266

 
309

Net Periodic Benefit Cost (Credit)
$
2,589

 
$
2,810

 
$
(1,710
)
 
$
(1,483
)
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Service Cost
$
6,244

 
$
4,964

 
$
632

 
$
759

Interest Cost
8,796

 
9,488

 
2,512

 
2,994

Expected Return on Plan Assets
(12,024
)
 
(11,571
)
 
(5,206
)
 
(5,262
)
Amortization of Prior Service Cost (Credit)
232

 
262

 
(3,867
)
 
(3,867
)
Amortization of Net Actuarial Loss
4,520

 
5,285

 
798

 
926

Net Periodic Benefit Cost (Credit)
$
7,768

 
$
8,428

 
$
(5,131
)
 
$
(4,450
)


216



7.  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 that started 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.



217



8.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets.  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.


218



The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of September 30, 2015 and December 31, 2014:

Notional Volume of Derivative Instruments
September 30, 2015
Primary Risk
Exposure
 
Unit of
Measure
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
(in thousands)
Commodity:
 
 
 
 
 
 

 
 

 
 

 
 

Power
 
MWhs
 
62,306

 
30,345

 
13,470

 
17,580

 
21,736

Coal
 
Tons
 
116

 
1,468

 

 

 
2,125

Natural Gas
 
MMBtus
 
256

 
174

 

 

 

Heating Oil and Gasoline
 
Gallons
 
1,763

 
836

 
1,858

 
1,019

 
1,166

Interest Rate
 
USD
 
$
2,645

 
$
1,794

 
$

 
$

 
$


Notional Volume of Derivative Instruments
December 31, 2014
Primary Risk
Exposure
 
Unit of
Measure
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
(in thousands)
Commodity:
 
 
 
 
 
 

 
 

 
 

 
 

Power
 
MWhs
 
32,479

 
23,774

 
20,334

 
16,765

 
20,469

Coal
 
Tons
 
279

 
500

 

 

 
1,500

Natural Gas
 
MMBtus
 
421

 
286

 

 

 

Heating Oil and Gasoline
 
Gallons
 
1,089

 
521

 
1,108

 
614

 
699

Interest Rate
 
USD
 
$
5,094

 
$
3,455

 
$

 
$

 
$


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 (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. 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 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. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.

AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. 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 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.


219



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, 2015 and December 31, 2014 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, 2015
 
December 31, 2014
Company
 
Cash Collateral
Received
Netted Against
Risk Management
Assets
 
Cash Collateral
Paid
Netted Against
Risk Management
Liabilities
 
Cash Collateral
Received
Netted Against
Risk Management
Assets
 
Cash Collateral
Paid
Netted Against
Risk Management
Liabilities
 
 
(in thousands)
APCo
 
$

 
$
1,688

 
$
68

 
$
98

I&M
 

 
333

 
163

 
47

OPCo
 

 
500

 

 
102

PSO
 

 
280

 

 
54

SWEPCo
 

 
319

 

 
62


220



The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of September 30, 2015 and December 31, 2014:

APCo

Fair Value of Derivative Instruments
September 30, 2015
 
 
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 - Nonaffiliated and Affiliated
 
$
34,278

 
$

 
$

 
$
34,278

 
$
(6,928
)
 
$
27,350

Long-term Risk Management Assets - Nonaffiliated
 
2,485

 

 

 
2,485

 
(450
)
 
2,035

Total Assets
 
36,763

 

 

 
36,763

 
(7,378
)
 
29,385

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities - Nonaffiliated
 
15,345

 

 

 
15,345

 
(8,443
)
 
6,902

Long-term Risk Management Liabilities - Nonaffiliated
 
1,596

 

 

 
1,596

 
(623
)
 
973

Total Liabilities
 
16,941

 

 

 
16,941

 
(9,066
)
 
7,875

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
19,822

 
$

 
$

 
$
19,822

 
$
1,688

 
$
21,510


APCo

Fair Value of Derivative Instruments
December 31, 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 - Nonaffiliated
 
$
32,903

 
$

 
$

 
$
32,903

 
$
(9,111
)
 
$
23,792

Long-term Risk Management Assets - Nonaffiliated
 
5,159

 

 

 
5,159

 
(268
)
 
4,891

Total Assets
 
38,062

 

 

 
38,062

 
(9,379
)
 
28,683

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities - Non Affiliated
 
20,161

 

 

 
20,161

 
(9,144
)
 
11,017

Long-term Risk Management Liabilities - Nonaffiliated
 
2,322

 

 

 
2,322

 
(265
)
 
2,057

Total Liabilities
 
22,483

 

 

 
22,483

 
(9,409
)
 
13,074

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
15,579

 
$

 
$

 
$
15,579

 
$
30

 
$
15,609


(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.


221



I&M

Fair Value of Derivative Instruments
September 30, 2015
 
 
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 - Nonaffiliated and Affiliated
 
$
16,675

 
$

 
$

 
$
16,675

 
$
(6,048
)
 
$
10,627

Long-term Risk Management Assets - Nonaffiliated
 
1,619

 

 

 
1,619

 
(281
)
 
1,338

Total Assets
 
18,294

 

 

 
18,294

 
(6,329
)
 
11,965

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities - Nonaffiliated
 
10,901

 

 

 
10,901

 
(6,286
)
 
4,615

Long-term Risk Management Liabilities - Nonaffiliated
 
1,624

 

 

 
1,624

 
(376
)
 
1,248

Total Liabilities
 
12,525

 

 

 
12,525

 
(6,662
)
 
5,863

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
5,769

 
$

 
$

 
$
5,769

 
$
333

 
$
6,102


I&M

Fair Value of Derivative Instruments
December 31, 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 - Nonaffiliated
 
$
28,545

 
$

 
$

 
$
28,545

 
$
(6,217
)
 
$
22,328

Long-term Risk Management Assets - Nonaffiliated
 
3,499

 

 

 
3,499

 
(182
)
 
3,317

Total Assets
 
32,044

 

 

 
32,044

 
(6,399
)
 
25,645

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities - Nonaffiliated
 
11,326

 

 

 
11,326

 
(6,103
)
 
5,223

Long-term Risk Management Liabilities - Nonaffiliated
 
1,575

 

 

 
1,575

 
(180
)
 
1,395

Total Liabilities
 
12,901

 

 

 
12,901

 
(6,283
)
 
6,618

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
19,143

 
$

 
$

 
$
19,143

 
$
(116
)
 
$
19,027


(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.


222



OPCo

Fair Value of Derivative Instruments
September 30, 2015
 
 
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
 
$

 
$

 
$

 
$

 
$

 
$

Long-term Risk Management Assets
 
23,265

 

 

 
23,265

 

 
23,265

Total Assets
 
23,265

 

 

 
23,265

 

 
23,265

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
3,271

 

 

 
3,271

 
(448
)
 
2,823

Long-term Risk Management Liabilities
 
4,923

 

 

 
4,923

 
(52
)
 
4,871

Total Liabilities
 
8,194

 

 

 
8,194

 
(500
)
 
7,694

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
15,071

 
$

 
$

 
$
15,071

 
$
500

 
$
15,571


OPCo

Fair Value of Derivative Instruments
December 31, 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
 
$
7,242

 
$

 
$

 
$
7,242

 
$

 
$
7,242

Long-term Risk Management Assets
 
45,102

 

 

 
45,102

 

 
45,102

Total Assets
 
52,344

 

 

 
52,344

 

 
52,344

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
2,045

 

 

 
2,045

 
(102
)
 
1,943

Long-term Risk Management Liabilities
 
3,013

 

 

 
3,013

 

 
3,013

Total Liabilities
 
5,058

 

 

 
5,058

 
(102
)
 
4,956

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
47,286

 
$

 
$

 
$
47,286

 
$
102

 
$
47,388


(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.


223



PSO

Fair Value of Derivative Instruments
September 30, 2015
 
 
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
 
$
1,166

 
$

 
$

 
$
1,166

 
$
(131
)
 
$
1,035

Long-term Risk Management Assets
 

 

 

 

 

 

Total Assets
 
1,166

 

 

 
1,166

 
(131
)
 
1,035

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
454

 

 

 
454

 
(384
)
 
70

Long-term Risk Management Liabilities
 
35

 

 

 
35

 
(27
)
 
8

Total Liabilities
 
489

 

 

 
489

 
(411
)
 
78

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
677

 
$

 
$

 
$
677

 
$
280

 
$
957


PSO

Fair Value of Derivative Instruments
December 31, 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
 
$
360

 
$

 
$

 
$
360

 
$
(360
)
 
$

Long-term Risk Management Assets
 

 

 

 

 

 

Total Assets
 
360

 

 

 
360

 
(360
)
 

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
1,332

 

 

 
1,332

 
(414
)
 
918

Long-term Risk Management Liabilities
 

 

 

 

 

 

Total Liabilities
 
1,332

 

 

 
1,332

 
(414
)
 
918

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
(972
)
 
$

 
$

 
$
(972
)
 
$
54

 
$
(918
)

(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.


224



SWEPCo

Fair Value of Derivative Instruments
September 30, 2015
 
 
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
 
$
1,442

 
$

 
$

 
$
1,442

 
$
(162
)
 
$
1,280

Long-term Risk Management Assets
 

 

 

 

 

 

Total Assets
 
1,442

 

 

 
1,442

 
(162
)
 
1,280

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
1,752

 

 

 
1,752

 
(450
)
 
1,302

Long-term Risk Management Liabilities
 
788

 

 

 
788

 
(31
)
 
757

Total Liabilities
 
2,540

 

 

 
2,540

 
(481
)
 
2,059

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
(1,098
)
 
$

 
$

 
$
(1,098
)
 
$
319

 
$
(779
)

SWEPCo

Fair Value of Derivative Instruments
December 31, 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
 
$
471

 
$

 
$

 
$
471

 
$
(440
)
 
$
31

Long-term Risk Management Assets
 

 

 

 

 

 

Total Assets
 
471

 

 

 
471

 
(440
)
 
31

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
1,584

 

 

 
1,584

 
(502
)
 
1,082

Long-term Risk Management Liabilities
 

 

 

 

 

 

Total Liabilities
 
1,584

 

 

 
1,584

 
(502
)
 
1,082

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
(1,113
)
 
$

 
$

 
$
(1,113
)
 
$
62

 
$
(1,051
)

(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.


225



The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and nine months ended September 30, 2015 and 2014:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 2015
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Electric Generation, Transmission and Distribution Revenues
 
$
(369
)
 
$
350

 
$
(917
)
 
$
(9
)
 
$
(7
)
Sales to AEP Affiliates
 
1,156

 
3,336

 

 

 

Other Operation Expense
 
(88
)
 
(63
)
 
(128
)
 
(109
)
 
(127
)
Maintenance Expense
 
(164
)
 
(86
)
 
(140
)
 
(88
)
 
(88
)
Purchased Electricity for Resale
 
831

 
15

 
30

 

 

Regulatory Assets (a)
 
861

 
(981
)
 

 
(190
)
 
188

Regulatory Liabilities (a)
 
3,197

 
(1,718
)
 
(22,281
)
 
(498
)
 
1,137

Total Gain (Loss) on Risk Management Contracts
 
$
5,424

 
$
853

 
$
(23,436
)
 
$
(894
)
 
$
1,103


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 Nine Months Ended September 30, 2015
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Electric Generation, Transmission and Distribution Revenues
 
$
790

 
$
3,591

 
$
(882
)
 
$
16

 
$
19

Sales to AEP Affiliates
 
1,511

 
4,341

 

 

 

Other Operation Expense
 
(287
)
 
(221
)
 
(389
)
 
(307
)
 
(373
)
Maintenance Expense
 
(503
)
 
(221
)
 
(396
)
 
(248
)
 
(265
)
Purchased Electricity for Resale
 
1,571

 
347

 
30

 

 

Regulatory Assets (a)
 
2,136

 
(1,213
)
 

 
615

 
(1,234
)
Regulatory Liabilities (a)
 
31,797

 
4,121

 
(24,880
)
 
5,076

 
14,446

Total Gain (Loss) on Risk Management Contracts
 
$
37,015

 
$
10,745

 
$
(26,517
)
 
$
5,152

 
$
12,593



226



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
)
(a)
Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis.

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

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. 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.”

In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale.



227



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 designated as cash flow hedges are included in Revenues 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, 2015, the Registrant Subsidiaries did not designate power derivatives as cash flow hedges. During the three and nine months ended September 30, 2014, APCo and I&M designated power 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. The impact of cash flow hedge accounting for these derivative contracts was immaterial and was discontinued effective March 31, 2014.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2015 and 2014, the Registrant Subsidiaries did not designate 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, 2015 and 2014, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges.

During the three and nine months ended September 30, 2015 and 2014, 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, 2015 and 2014, see Note 3.


228



Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2015 and December 31, 2014 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
September 30, 2015
 
 
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
 
$

 
$

 
$

 
$

 
$

 
$
3,805

I&M
 

 

 

 

 

 
(13,604
)
OPCo
 

 

 

 

 

 
4,572

PSO
 

 

 

 

 

 
4,374

SWEPCo
 

 

 

 

 

 
(9,470
)
 
 
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
 
$

 
$
734

 
0
I&M
 

 
(1,277
)
 
0
OPCo
 

 
1,282

 
0
PSO
 

 
771

 
0
SWEPCo
 

 
(1,728
)
 
0

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 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
 
$

 
$

 
$

 
$

 
$

 
$
3,896

I&M
 

 

 

 

 

 
(14,406
)
OPCo
 

 

 

 

 

 
5,602

PSO
 

 

 

 

 

 
4,943

SWEPCo
 

 

 

 

 

 
(11,036
)
 
 
Expected to be Reclassified to
Net Income During the Next
Twelve Months
Company
 
Commodity
 
Interest Rate
and Foreign
Currency
 
 
(in thousands)
APCo
 
$

 
$
275

I&M
 

 
(1,090
)
OPCo
 

 
1,372

PSO
 

 
759

SWEPCo
 

 
(1,998
)

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

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


229



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 the Registrant Subsidiaries' exposure if credit ratings were to decline below a specified rating threshold as of September 30, 2015 and December 31, 2014:
 
 
September 30, 2015
 
 
 
 
Amount of Collateral
 
 
 
 
 
 
 
 
the Registrant Subsidiaries
 
 
 
 
 
 
 
 
Would Have Been Required
 
 
 
 
 
 
Fair Value
 
to Post for Derivative
 
Amount of Collateral
 
Amount of
 
 
of Contracts
 
Contracts as well as Non-
 
the Registrant Subsidiaries
 
Collateral
 
 
with Credit
 
Derivative Contracts Subject
 
Would Have Been Required
 
Attributable to
 
 
Downgrade
 
to the Same Master Netting
 
to Post Attributable to
 
Other
Company
 
Triggers
 
Arrangement
 
RTOs and ISOs
 
Contracts
 
 
(in thousands)
APCo
 
$

 
$

 
$
2,913

 
$
97

I&M
 

 

 
1,976

 
66

OPCo
 

 

 

 

PSO
 

 

 
2,692

 
3,247

SWEPCo
 

 

 
3,328

 
58

 
 
December 31, 2014
 
 
 
 
Amount of Collateral
 
 
 
 
 
 
 
 
the Registrant Subsidiaries
 
 
 
 
 
 
 
 
Would Have Been Required
 
 
 
 
 
 
Fair Value
 
to Post for Derivative
 
Amount of Collateral
 
Amount of
 
 
of Contracts
 
Contracts as well as Non-
 
the Registrant Subsidiaries
 
Collateral
 
 
with Credit
 
Derivative Contracts Subject
 
Would Have Been Required
 
Attributable to
 
 
Downgrade
 
to the Same Master Netting
 
to Post Attributable to
 
Other
Company
 
Triggers
 
Arrangement
 
RTOs and ISOs
 
Contracts
 
 
(in thousands)
APCo
 
$

 
$

 
$
6,339

 
$
74

I&M
 

 

 
4,299

 
47

OPCo
 

 

 

 

PSO
 

 

 
693

 
4,111

SWEPCo
 

 

 
877

 
166


230



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, 2015 and December 31, 2014:
 
 
September 30, 2015
 
 
Liabilities for
 
 
 
Additional
 
 
Contracts with Cross
 
 
 
Settlement
 
 
Default Provisions
 
 
 
Liability if Cross
 
 
Prior to Contractual
 
Amount of Cash
 
Default Provision
Company
 
Netting Arrangements
 
Collateral Posted
 
is Triggered
 
 
(in thousands)
APCo
 
$
5,310

 
$

 
$
5,288

I&M
 
3,601

 

 
3,586

OPCo
 

 

 

PSO
 

 

 

SWEPCo
 

 

 

 
 
December 31, 2014
 
 
Liabilities for
 
 
 
Additional
 
 
Contracts with Cross
 
 
 
Settlement
 
 
Default Provisions
 
 
 
Liability if Cross
 
 
Prior to Contractual
 
Amount of Cash
 
Default Provision
Company
 
Netting Arrangements
 
Collateral Posted
 
is Triggered
 
 
(in thousands)
APCo
 
$
9,043

 
$

 
$
9,012

I&M
 
6,134

 

 
6,113

OPCo
 

 

 

PSO
 

 

 

SWEPCo
 

 

 



231



9.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

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

232



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, 2015 and December 31, 2014 are summarized in the following table:
 
 
September 30, 2015
 
December 31, 2014
Company
 
Book Value
 
Fair Value
 
Book Value
 
Fair Value
 
 
(in thousands)
APCo
 
$
3,955,295

 
$
4,460,140

 
$
3,980,274

 
$
4,711,210

I&M
 
2,060,651

 
2,241,930

 
2,027,397

 
2,255,124

OPCo
 
2,166,050

 
2,502,105

 
2,297,123

 
2,709,452

PSO
 
1,290,973

 
1,424,300

 
1,041,036

 
1,216,205

SWEPCo
 
2,283,966

 
2,446,716

 
2,140,437

 
2,402,639


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.

233



The following is a summary of nuclear trust fund investments as of September 30, 2015 and December 31, 2014:
 
September 30, 2015
 
December 31, 2014
 
 
 
Gross
 
Other-Than-
 
 
 
Gross
 
Other-Than-
 
Fair
 
Unrealized
 
Temporary
 
Fair
 
Unrealized
 
Temporary
 
Value
 
Gains
 
Impairments
 
Value
 
Gains
 
Impairments
 
(in thousands)
Cash and Cash Equivalents
$
164,353

 
$

 
$

 
$
19,966

 
$

 
$

Fixed Income Securities:
 

 
 

 
 

 
 

 
 

 
 

United States Government
704,344

 
45,005

 
(2,291
)
 
697,042

 
44,615

 
(5,016
)
Corporate Debt
62,118

 
3,682

 
(1,043
)
 
47,792

 
4,523

 
(1,018
)
State and Local Government
50,018

 
996

 
(324
)
 
208,553

 
1,206

 
(319
)
Subtotal Fixed Income Securities
816,480

 
49,683

 
(3,658
)
 
953,387

 
50,344

 
(6,353
)
Equity Securities - Domestic
1,066,427

 
516,206

 
(80,280
)
 
1,122,379

 
598,788

 
(79,142
)
Spent Nuclear Fuel and Decommissioning Trusts
$
2,047,260

 
$
565,889

 
$
(83,938
)
 
$
2,095,732

 
$
649,132

 
$
(85,495
)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2015 and 2014:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(in thousands)
Proceeds from Investment Sales
 
$
921,552

 
$
263,738

 
$
1,437,336

 
$
746,272

Purchases of Investments
 
938,438

 
280,626

 
1,479,149

 
789,461

Gross Realized Gains on Investment Sales
 
15,030

 
7,617

 
33,840

 
24,835

Gross Realized Losses on Investment Sales
 
13,167

 
1,739

 
22,823

 
10,447


The adjusted cost of fixed income securities was $766 million and $903 million as of September 30, 2015 and December 31, 2014, respectively.  The adjusted cost of equity securities was $551 million and $524 million as of September 30, 2015 and December 31, 2014, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2015 was as follows:
 
Fair Value of Fixed Income Securities
 
(in thousands)
Within 1 year
$
166,336

1 year – 5 years
335,823

5 years – 10 years
140,129

After 10 years
174,192

Total
$
816,480



234



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, 2015 and December 31, 2014.  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, 2015
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash for Securitized Funding (a)
 
$
7,436

 
$

 
$

 
$
57

 
$
7,493

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets – Nonaffiliated and Affiliated
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
185

 
12,785

 
23,743

 
(7,328
)
 
29,385

 
 
 
 
 
 
 
 
 
 
 
Total Assets:
 
$
7,621

 
$
12,785

 
$
23,743

 
$
(7,271
)
 
$
36,878

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities – Nonaffiliated
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$
198

 
$
16,031

 
$
662

 
$
(9,016
)
 
$
7,875


APCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2014
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash for Securitized Funding (a)
 
$
15,599

 
$

 
$

 
$
33

 
$
15,632

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets – Nonaffiliated
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
206

 
20,197

 
17,654

 
(9,374
)
 
28,683

 
 
 
 
 
 
 
 
 
 
 
Total Assets:
 
$
15,805

 
$
20,197

 
$
17,654

 
$
(9,341
)
 
$
44,315

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities – Nonaffiliated
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$
227

 
$
20,339

 
$
1,912

 
$
(9,404
)
 
$
13,074


235



I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2015
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets – Nonaffiliated and Affiliated
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$
126

 
$
10,347

 
$
7,795

 
$
(6,303
)
 
$
11,965

 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 

 
 

 
 

 
 

 
 

Cash and Cash Equivalents (d)
 
157,409

 

 

 
6,944

 
164,353

Fixed Income Securities:
 
 

 
 

 
 

 
 

 
 

United States Government
 

 
704,344

 

 

 
704,344

Corporate Debt
 

 
62,118

 

 

 
62,118

State and Local Government
 

 
50,018

 

 

 
50,018

Subtotal Fixed Income Securities
 

 
816,480

 

 

 
816,480

Equity Securities - Domestic (e)
 
1,066,427

 

 

 

 
1,066,427

Total Spent Nuclear Fuel and Decommissioning Trusts
 
1,223,836

 
816,480

 

 
6,944

 
2,047,260

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
1,223,962

 
$
826,827

 
$
7,795

 
$
641

 
$
2,059,225

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities – Nonaffiliated
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$
135

 
$
10,945

 
$
1,419

 
$
(6,636
)
 
$
5,863


I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2014
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets – Nonaffiliated
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$
140

 
$
15,893

 
$
16,008

 
$
(6,396
)
 
$
25,645

 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 

 
 

 
 

 
 

 
 

Cash and Cash Equivalents (d)
 
9,418

 

 

 
10,548

 
19,966

Fixed Income Securities:
 
 

 
 

 
 

 
 

 


United States Government
 

 
697,042

 

 

 
697,042

Corporate Debt
 

 
47,792

 

 

 
47,792

State and Local Government
 

 
208,553

 

 

 
208,553

Subtotal Fixed Income Securities
 

 
953,387

 

 

 
953,387

Equity Securities - Domestic (e)
 
1,122,379

 

 

 

 
1,122,379

Total Spent Nuclear Fuel and Decommissioning Trusts
 
1,131,797

 
953,387

 

 
10,548

 
2,095,732

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
1,131,937

 
$
969,280

 
$
16,008

 
$
4,152

 
$
2,121,377

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities – Nonaffiliated
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$
154

 
$
11,440

 
$
1,304

 
$
(6,280
)
 
$
6,618


236



OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2015
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash for Securitized Funding (a)
 
$
16,195

 
$

 
$

 
$
9

 
$
16,204

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 

 

 
20,719

 
2,546

 
23,265

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
16,195

 
$

 
$
20,719

 
$
2,555

 
$
39,469

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (b) (c)
 
$

 
$
639

 
$
5,009

 
$
2,046

 
$
7,694


OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2014
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash for Securitized Funding (a)
 
$
408

 
$

 
$

 
$
28,288

 
$
28,696

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 

 

 
52,343

 
1

 
52,344

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
408

 
$

 
$
52,343

 
$
28,289

 
$
81,040

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$

 
$
1,116

 
$
3,941

 
$
(101
)
 
$
4,956



237



PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2015
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$

 
$

 
$
1,166

 
$
(131
)
 
$
1,035

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$

 
$
358

 
$
131

 
$
(411
)
 
$
78


PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2014
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$

 
$

 
$
360

 
$
(360
)
 
$

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$

 
$
595

 
$
737

 
$
(414
)
 
$
918



238



SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2015
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
$
11,688

 
$

 
$

 
$
2,570

 
$
14,258

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 

 

 
1,442

 
(162
)
 
1,280

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
11,688

 
$

 
$
1,442

 
$
2,408

 
$
15,538

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$

 
$
2,378

 
$
162

 
$
(481
)
 
$
2,059


SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2014
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
$
12,660

 
$

 
$

 
$
1,696

 
$
14,356

 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 

 
31

 
439

 
(439
)
 
31

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
12,660

 
$
31

 
$
439

 
$
1,257

 
$
14,387

 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 

 
 

 
 

 
 

 
 

Risk Management Commodity Contracts (b) (c)
 
$

 
$
684

 
$
899

 
$
(501
)
 
$
1,082


(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, 2015 and 2014.

239



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, 2015
 
APCo (a)
 
I&M (a)
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of June 30, 2015
 
$
33,836

 
$
11,844

 
$
37,657

 
$
1,699

 
$
2,039

Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c)
 
5,065

 
885

 
(28
)
 
(280
)
 
2,366

Purchases, Issuances and Settlements (d)
 
(13,965
)
 
(3,604
)
 
348

 
(176
)
 
(2,912
)
Changes in Fair Value Allocated to Regulated Jurisdictions (h)
 
(1,855
)
 
(2,749
)
 
(22,267
)
 
(208
)
 
(213
)
Balance as of September 30, 2015
 
$
23,081

 
$
6,376

 
$
15,710

 
$
1,035

 
$
1,280

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) (b) (c)
 
(5,629
)
 
(3,832
)
 
(3,639
)
 
2

 
2

Purchases, Issuances and Settlements (d)
 
(1,560
)
 
(1,244
)
 
(637
)
 

 

Transfers into Level 3 (e) (f)
 
(6
)
 
(4
)
 

 

 

Transfers out of Level 3 (f) (g)
 
(30
)
 
(20
)
 

 

 

Changes in Fair Value Allocated to Regulated Jurisdictions (h)
 
4,843

 
4,319

 
2,865

 
335

 
409

Balance as of September 30, 2014
 
$
16,012

 
$
12,142

 
$
7,889

 
$
334

 
$
408

Nine Months Ended September 30, 2015
 
APCo (a)
 
I&M (a)
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of December 31, 2014
 
$
15,742

 
$
14,704

 
$
48,402

 
$
(377
)
 
$
(460
)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c)
 
1,757

 
(193
)
 
1,182

 
(176
)
 
9,187

Purchases, Issuances and Settlements (d)
 
(16,124
)
 
(12,807
)
 
(7,906
)
 
553

 
(8,727
)
Transfers out of Level 3 (f) (g)
 
1,167

 
792

 

 

 

Changes in Fair Value Allocated to Regulated Jurisdictions (h)
 
20,539

 
3,880

 
(25,968
)
 
1,035

 
1,280

Balance as of September 30, 2015
 
$
23,081

 
$
6,376

 
$
15,710

 
$
1,035

 
$
1,280


240



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) (b) (c)
 
29,467

 
18,438

 
30,768

 

 

Purchases, Issuances and Settlements (d)
 
(32,213
)
 
(20,301
)
 
(33,688
)
 

 

Transfers into Level 3 (e) (f)
 
(3,648
)
 
(2,475
)
 

 

 

Transfers out of Level 3 (f) (g)
 
(32
)
 
(22
)
 

 

 

Changes in Fair Value Allocated to Regulated Jurisdictions (h)
 
11,876

 
9,338

 
7,889

 
334

 
408

Balance as of September 30, 2014
 
$
16,012

 
$
12,142

 
$
7,889

 
$
334

 
$
408


(a)
Includes both affiliated and nonaffiliated transactions.
(b)
Included in revenues on the condensed statements of income.
(c)
Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(d)
Represents the settlement of risk management commodity contracts for the reporting period.
(e)
Represents existing assets or liabilities that were previously categorized as Level 2.
(f)
Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(g)
Represents existing assets or liabilities that were previously categorized as Level 3.
(h)
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, 2015 and December 31, 2014:

Significant Unobservable Inputs
September 30, 2015
APCo
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
$
8,724

 
$
451

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
13.03

 
$
48.17

 
$
34.76

FTRs
15,019

 
211

 
Discounted Cash Flow 
 
Forward Market Price 
 
(5.95
)
 
11.60

 
1.53

Total
$
23,743

 
$
662

 
 
 
 
 
 

 
 

 
 

Significant Unobservable Inputs
December 31, 2014
APCo
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
$
5,801

 
$
1,799

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
13.43

 
$
123.02

 
$
52.47

FTRs
11,853

 
113

 
Discounted Cash Flow 
 
Forward Market Price 
 
(14.63
)
 
20.02

 
1.01

Total
$
17,654

 
$
1,912

 
 
 
 
 
 

 
 

 
 


241



Significant Unobservable Inputs
September 30, 2015
I&M
 
 
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
$
7,147

 
$
295

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
13.03

 
$
48.17

 
$
34.76

FTRs
648

 
1,124

 
Discounted Cash Flow 
 
Forward Market Price 
 
(5.95
)
 
11.60

 
1.53

Total
$
7,795

 
$
1,419

 
 
 
 
 
 

 
 

 
 

Significant Unobservable Inputs
December 31, 2014
I&M
 
 
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
$
6,375

 
$
1,219

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
13.43

 
$
123.02

 
$
52.47

FTRs
9,633

 
85

 
Discounted Cash Flow 
 
Forward Market Price 
 
(14.63
)
 
20.02

 
1.01

Total
$
16,008

 
$
1,304

 
 
 
 
 
 

 
 

 
 


Significant Unobservable Inputs
September 30, 2015
OPCo
 
 
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
$
20,719

 
$
5,009

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
35.71

 
$
165.93

 
$
85.99


Significant Unobservable Inputs
December 31, 2014
OPCo
 
 
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
$
45,101

 
$
3,941

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
48.25

 
$
159.92

 
$
84.04

FTRs
7,242

 

 
Discounted Cash Flow 
 
Forward Market Price 
 
(14.63
)
 
20.02

 
1.01

Total
$
52,343

 
$
3,941

 
 
 
 
 
 
 
 
 
 


242



Significant Unobservable Inputs
September 30, 2015
PSO
 
 
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
FTRs
$
1,166

 
$
131

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
(5.95
)
 
$
11.60

 
$
1.53


Significant Unobservable Inputs
December 31, 2014
PSO
 
 
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
FTRs
$
360

 
$
737

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
(14.63
)
 
$
20.02

 
$
1.01


Significant Unobservable Inputs
September 30, 2015
SWEPCo
 
 
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
FTRs
$
1,442

 
$
162

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
(5.95
)
 
$
11.60

 
$
1.53


Significant Unobservable Inputs
December 31, 2014
SWEPCo
 
 
 
 
 
 
 
Significant
 
Forward Price Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input (a)
 
Low
 
High
 
Average
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
FTRs
$
439

 
$
899

 
Discounted Cash Flow 
 
Forward Market Price 
 
$
(14.63
)
 
$
20.02

 
$
1.01


(a)
Represents market prices in dollars per MWh.

The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrant Subsidiaries as of September 30, 2015:

Sensitivity of Fair Value Measurements
September 30, 2015
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)

243



10.  INCOME TAXES

AEP System Tax Allocation Agreement

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

Federal and State Income Tax Audit Status

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 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 the Registrant Subsidiaries' 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 the Registrant Subsidiaries' net income.  The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009.

State Tax Legislation

House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrant Subsidiaries' net income, cash flows or financial condition.



244



11.  FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2015 are shown in the tables below:
Company
 
Type of Debt
 
Principal Amount (a)
 
Interest Rate
 
Due Date
Issuances:
 
 
 
(in thousands)
 
(%)
 
 
APCo
 
Pollution Control Bonds
 
$
86,000

 
1.90
 
2019
APCo
 
Senior Unsecured Notes
 
350,000

 
4.45
 
2045
APCo
 
Senior Unsecured Notes
 
300,000

 
3.40
 
2025
I&M
 
Notes Payable
 
111,300

 
Variable
 
2019
I&M
 
Other Long-term Debt
 
100,000

 
Variable
 
2018
PSO
 
Senior Unsecured Notes
 
125,000

 
3.17
 
2025
PSO
 
Senior Unsecured Notes
 
125,000

 
4.09
 
2045
SWEPCo
 
Pollution Control Bonds
 
53,500

 
1.60
 
2019
SWEPCo
 
Senior Unsecured Notes
 
400,000

 
3.90
 
2045

(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
 
$
28

 
13.718
 
2026
APCo
 
Notes Payable - Affiliated
 
86,000

 
3.125
 
2015
APCo
 
Securitization Bonds
 
22,524

 
2.008
 
2024
APCo
 
Senior Unsecured Notes
 
350,000

 
7.95
 
2020
APCo
 
Senior Unsecured Notes
 
300,000

 
3.40
 
2015
I&M
 
Notes Payable
 
18,600

 
Variable
 
2016
I&M
 
Notes Payable
 
20,601

 
Variable
 
2017
I&M
 
Notes Payable
 
26,512

 
Variable
 
2019
I&M
 
Notes Payable
 
16,265

 
Variable
 
2019
I&M
 
Notes Payable
 
1,273

 
Variable
 
2016
I&M
 
Notes Payable
 
882

 
2.12
 
2016
I&M
 
Other Long-term Debt
 
93,500

 
Variable
 
2015
I&M
 
Other Long-term Debt
 
838

 
6.00
 
2025
OPCo
 
Other Long-term Debt
 
58

 
1.149
 
2028
OPCo
 
Pollution Control Bonds
 
86,000

 
3.125
 
2015
OPCo
 
Securitization Bonds
 
45,426

 
0.958
 
2018
PSO
 
Other Long-term Debt
 
319

 
3.00
 
2027
SWEPCo
 
Notes Payable
 
3,250

 
4.58
 
2032
SWEPCo
 
Pollution Control Bonds
 
53,500

 
3.25
 
2015
SWEPCo
 
Senior Unsecured Notes
 
100,000

 
5.375
 
2015
SWEPCo
 
Senior Unsecured Notes
 
150,000

 
4.90
 
2015

As of September 30, 2015, trustees held on behalf of I&M and OPCo, $40 million and $345 million, respectively, of their reacquired Pollution Control Bonds.


245



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. This restriction does not limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

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.

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, and a Nonutility Money Pool, which funds a majority of AEP's nonutility subsidiaries.  The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC.  The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2015 and December 31, 2014 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, 2015 are described in the following table:
 
 
Maximum
 
 
 
Average
 
 
 
Net Loans to
 
 
 
 
Borrowings
 
Maximum
 
Borrowings
 
Average
 
(Borrowings from)
 
Authorized
 
 
from the
 
Loans to the
 
from the
 
Loans to the
 
the Utility Money
 
Short-term
 
 
Utility
 
Utility
 
Utility
 
Utility
 
Pool as of
 
Borrowing
Company
 
Money Pool
 
Money Pool
 
Money Pool
 
Money Pool
 
September 30, 2015
 
Limit
 
 
(in thousands)
APCo
 
$
82,417

 
$
694,785

 
$
46,664

 
$
97,657

 
$
(11,689
)
 
$
600,000

I&M
 
200,032

 
13,515

 
136,890

 
13,503

 
(137,496
)
 
500,000

OPCo
 

 
367,472

 

 
256,020

 
279,129

 
400,000

PSO
 
165,947

 
152,498

 
113,117

 
74,225

 
116,345

 
300,000

SWEPCo
 
112,481

 
299,932

 
52,596

 
121,845

 
43,073

 
350,000



246



The activity in the above table does not include short-term lending activity of SWEPCo's wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2015 and December 31, 2014 are included in Advances to Affiliates on SWEPCo's condensed balance sheets. For the nine months ended September 30, 2015, Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool:
Maximum
 
Maximum
 
Average
 
Average
 
Loans
Borrowings
 
Loans
 
Borrowings
 
Loans
 
to the Nonutility
from the Nonutility
 
to the Nonutility
 
from the Nonutility
 
to the Nonutility
 
Money Pool as of
Money Pool
 
Money Pool
 
Money Pool
 
Money Pool
 
September 30, 2015
(in thousands)
$

 
$
1,948

 
$

 
$
1,945

 
$
1,946


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,
 
 
2015
 
2014
Maximum Interest Rate
 
0.59
%
 
0.33
%
Minimum Interest Rate
 
0.39
%
 
0.24
%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2015 and 2014 are summarized for all Registrant Subsidiaries in the following table:
 
 
Average Interest Rate
 
Average Interest Rate
 
 
for Funds Borrowed
 
for Funds Loaned
 
 
from the Utility Money Pool for
 
to the Utility Money Pool for
 
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
Company
 
2015
 
2014
 
2015
 
2014
APCo
 
0.46
%
 
0.26
%
 
0.46
%
 
0.28
%
I&M
 
0.47
%
 
0.27
%
 
0.46
%
 
0.30
%
OPCo
 
%
 
0.27
%
 
0.47
%
 
0.29
%
PSO
 
0.49
%
 
0.27
%
 
0.46
%
 
%
SWEPCo
 
0.46
%
 
0.28
%
 
0.48
%
 
0.27
%

Maximum, minimum and average interest rates for funds either borrowed from or loaned to the Nonutility Money Pool for the nine months ended September 30, 2015 and 2014 are summarized for Mutual Energy SWEPCo, LLC in the following table:
 
 
Maximum
 
Minimum
 
Maximum
 
Minimum
 
Average
 
Average
 
 
Interest Rate
 
Interest Rate
 
Interest Rate
 
Interest Rate
 
Interest Rate
 
Interest Rate
 
 
for Funds
 
for Funds
 
for Funds
 
for Funds
 
for Funds
 
for Funds
Nine Months
 
Borrowed from
 
Borrowed from
 
Loaned to
 
Loaned to
 
Borrowed from
 
Loaned to
Ended
 
the Nonutility
 
the Nonutility
 
the Nonutility
 
the Nonutility
 
the Nonutility
 
the Nonutility
September 30,
 
Money Pool
 
Money Pool
Money Pool
 
Money Pool
 
Money Pool
 
Money Pool
2015
 
%
 
%
 
0.59
%
 
0.39
%
 
%
 
0.47
%
2014
 
%
 
%
 
0.33
%
 
%
 
%
 
0.28
%

Credit Facilities

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


247



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 2017.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2015 and December 31, 2014 was as follows:
 
 
September 30,
 
December 31,
Company
 
2015
 
2014
 
 
(in thousands)
APCo
 
$
125,153

 
$
159,823

I&M
 
139,481

 
137,459

OPCo
 
354,276

 
365,834

PSO
 
146,039

 
112,905

SWEPCo
 
176,113

 
148,668


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
 
2015
 
2014
 
2015
 
2014
 
 
(in thousands)
APCo
 
$
1,952

 
$
2,166

 
$
5,979

 
$
6,626

I&M
 
2,191

 
2,011

 
6,611

 
5,836

OPCo
 
8,545

 
7,213

 
23,228

 
21,358

PSO
 
1,709

 
1,745

 
4,455

 
4,417

SWEPCo
 
1,997

 
1,890

 
5,344

 
5,035


The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Company
 
2015
 
2014
 
2015
 
2014
 
 
(in thousands)
APCo
 
$
355,275

 
$
354,406

 
$
1,115,492

 
$
1,137,564

I&M
 
401,518

 
372,422

 
1,192,137

 
1,132,603

OPCo
 
670,677

 
668,112

 
1,949,042

 
1,980,764

PSO
 
411,523

 
398,567

 
1,025,909

 
1,014,320

SWEPCo
 
468,027

 
466,828

 
1,222,294

 
1,278,325



248



12.  VARIABLE INTEREST ENTITIES

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

SWEPCo is the primary beneficiary of Sabine.  I&M is the primary beneficiary of DCC Fuel.  OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding.  APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding.  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.
 
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, 2015 and 2014 were $41 million and $41 million, respectively, and for the nine months ended September 30, 2015 and 2014 were $124 million and $121 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, 2015 and December 31, 2014
(in thousands)
 
 
Sabine
ASSETS
 
2015
 
2014
Current Assets
 
$
61,025

 
$
67,981

Net Property, Plant and Equipment
 
143,815

 
145,491

Other Noncurrent Assets
 
60,160

 
51,578

Total Assets
 
$
265,000

 
$
265,050

 
 
 
 
 
LIABILITIES AND EQUITY
 
 

 
 

Current Liabilities
 
$
40,311

 
$
36,286

Noncurrent Liabilities
 
224,371

 
228,349

Equity
 
318

 
415

Total Liabilities and Equity
 
$
265,000

 
$
265,050


249



I&M has nuclear fuel lease agreements with DCC Fuel, which 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 DCC Fuel 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, 2015 and 2014 were $29 million and $28 million, respectively, and for the nine months ended September 30, 2015 and 2014 were $86 million and $84 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.  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, 2015 and December 31, 2014
(in thousands)
 
 
DCC Fuel
ASSETS
 
2015
 
2014
Current Assets
 
$
104,273

 
$
97,361

Net Property, Plant and Equipment
 
193,447

 
158,121

Other Noncurrent Assets
 
99,811

 
79,705

Total Assets
 
$
397,531

 
$
335,187

 
 
 
 
 
LIABILITIES AND EQUITY
 
 

 
 

Current Liabilities
 
$
98,173

 
$
86,026

Noncurrent Liabilities
 
299,358

 
249,161

Total Liabilities and Equity
 
$
397,531

 
$
335,187


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 $187 million and $232 million as of September 30, 2015 and December 31, 2014, respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets.  Ohio Phase-in-Recovery Funding has securitized assets of $92 million and $110 million as of September 30, 2015 and December 31, 2014, 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. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s condensed balance sheets.


250



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, 2015 and December 31, 2014
(in thousands)


Ohio
Phase-In Recovery
Funding
ASSETS

2015

2014
Current Assets

$
20,236


$
32,676

Other Noncurrent Assets (a)

175,189


209,922

Total Assets

$
195,425


$
242,598



 




LIABILITIES AND EQUITY

 




Current Liabilities

$
46,592


$
47,099

Noncurrent Liabilities

147,496


194,162

Equity

1,337


1,337

Total Liabilities and Equity

$
195,425


$
242,598

(a)
Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $81 million and $97 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 $345 million and $368 million as of September 30, 2015 and December 31, 2014, respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets.  Appalachian Consumer Rate Relief Funding has securitized assets of $333 million and $350 million as of September 30, 2015 and December 31, 2014, 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. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s condensed balance sheets.


251



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, 2015 and December 31, 2014
(in thousands)
 
 
Appalachian Consumer Rate
Relief Funding
ASSETS
 
2015
 
2014
Current Assets
 
$
10,914

 
$
18,099

Other Noncurrent Assets (a)
 
341,127

 
358,264

Total Assets
 
$
352,041

 
$
376,363

 
 
 
 
 
LIABILITIES AND EQUITY
 
 

 
 
Current Liabilities
 
$
24,617

 
$
26,809

Noncurrent Liabilities
 
325,534

 
347,652

Equity
 
1,890

 
1,902

Total Liabilities and Equity
 
$
352,041

 
$
376,363


(a)
Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 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, 2015 and 2014 were $30 million and $24 million, respectively, and for the nine months ended September 30, 2015 and 2014 were $59 million and $31 million, respectively.  SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC.  SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheets.

SWEPCo’s investment in DHLC was:
 
 
September 30, 2015
 
December 31, 2014
 
 
 
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
 
5,950

 
5,950

 
3,819

 
3,819

 
SWEPCo's Guarantee of Debt
 

 
95,180

(a)

 
104,334

(a)
 
 
 
 
 
 
 
 
 
 
Total Investment in DHLC
 
$
13,593

 
$
108,773

 
$
11,462

 
$
115,796

 

(a)
Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $40 million and $56 million in 2015 and 2014, respectively.


252



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

Total AEPSC billings to the Registrant Subsidiaries were as follows:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Company
 
2015
 
2014
 
2015
 
2014
 
 
(in thousands)
APCo
 
$
63,687

 
$
50,143

 
$
164,657

 
$
154,239

I&M
 
37,506

 
30,613

 
102,141

 
92,686

OPCo
 
48,471

 
41,212

 
128,608

 
120,696

PSO
 
29,851

 
24,317

 
77,817

 
71,646

SWEPCo
 
39,150

 
32,787

 
102,564

 
98,528


The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows:
 
 
September 30, 2015
 
December 31, 2014
Company
 
As Reported on the
Balance Sheet
 
Maximum
Exposure
 
As Reported on the
Balance Sheet
 
Maximum
Exposure
 
 
(in thousands)
APCo
 
$
23,783

 
$
23,783

 
$
30,692

 
$
30,692

I&M
 
13,676

 
13,676

 
22,480

 
22,480

OPCo
 
18,770

 
18,770

 
24,695

 
24,695

PSO
 
10,713

 
10,713

 
15,338

 
15,338

SWEPCo
 
14,295

 
14,295

 
20,772

 
20,772


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 and AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligation 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. Total billings to I&M from AEGCo for the three months ended September 30, 2015 and 2014 were $67 million and $67 million, respectively, and for the nine months ended September 30, 2015 and 2014 were $182 million and $202 million, respectively. The carrying amount of I&M's liabilities associated with AEGCo as of September 30, 2015 and December 31, 2014 was $17 million and $20 million, respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo's lease, see "Rockport Lease" section of Note 13 in the 2014 Annual Report.

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13. PROPERTY, PLANT AND EQUIPMENT

Asset Retirement Obligations (ARO)

The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal.  I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned.  Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use.  The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely.  The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected.

As of September 30, 2015 and December 31, 2014, I&M's ARO liability for nuclear decommissioning of the Cook Plant was $1.31 billion and $1.27 billion, respectively.  These liabilities are reflected in Asset Retirement Obligations on I&M's condensed balance sheets. As of September 30, 2015 and December 31, 2014, the fair value of I&M's assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.74 billion and $1.79 billion, respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M's condensed balance sheets.

The Registrant Subsidiaries recorded an increase in asset retirement obligations in the second quarter of 2015, partially related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants.  The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment.

The following is a reconciliation of the aggregate carrying amounts of ARO by Registrant Subsidiary:
 
 
ARO as of
 
 
 
 
 
 
 
Revisions in
 
 
 
 
December 31,
 
Accretion
 
Liabilities
 
Liabilities
 
Cash Flow
 
ARO as of
Company
 
2014
 
Expense
 
Incurred
 
Settled
 
Estimates
 
September 30, 2015
 
 
(in thousands)
APCo (a)(d)
 
$
148,377

 
$
6,239

 
$

 
$
(23,471
)
 
$
16,977

 
$
148,122

I&M (a)(b)(d)
 
1,342,549

 
47,918

 

 
(3,977
)
 
5,638

 
1,392,128

OPCo (d)(e)
 
1,361

 
62

 

 
(8
)
 

 
1,415

PSO (a)(d)
 
38,020

 
1,923

 
5,336

 
(125
)
 
1,916

 
47,070

SWEPCo (a)(c)(d)
 
94,394

 
4,299

 
12,191

 
(3,358
)
 
6,349

 
113,875


(a)
Includes ARO related to ash disposal facilities.
(b)
Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.31 billion and $1.27 billion as of September 30, 2015 and December 31, 2014.
(c)
Includes ARO related to Sabine and DHLC.
(d)
Includes ARO related to asbestos removal.
(e)
Not impacted by the CCR rule.


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14.  DISPOSITION PLANT SEVERANCE

Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits.

The Registrant Subsidiaries' disposition plant severance activity for the nine months ended September 30, 2015 is described in the following table:
 
 
Balance as of
 
Expense
Allocation from
 
Incurred by
Registrant
 
 
 
 
 
Remaining
Balance as of
Company
 
December 31, 2014
 
AEPSC
 
Subsidiaries
 
Settled
 
Adjustments
 
September 30, 2015
 
 
(in thousands)
APCo
 
$
9,304

 
$
(6
)
 
$
849

 
$
(6,385
)
(a)
$
(119
)
 
$
3,643

I&M
 
8,023

 
(2
)
 
351

 
(5,110
)
 

 
3,262

PSO
 
134

 
(3
)
 
415

 
(121
)
 

 
425

SWEPCo
 
84

 
(4
)
 

 
(79
)
 

 
1


(a) Settled includes amounts received from affiliates for expenses related to joint plant.

The Registrant Subsidiaries recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amount incurred in 2014 by Registrant Subsidiary was as follows:
Company
 
Total Cost Incurred
 
 
(in thousands)
APCo
 
$
7,112

I&M
 
8,185

OPCo
 
80

PSO
 
288

SWEPCo
 
289


These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income.  The remaining liability is included in Other Current Liabilities on the condensed balance sheets.  The Registrant Subsidiaries incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative.


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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 2014 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

Customer Demand

AEP's weather-normalized retail sales volumes for the third quarter of 2015 increased by 0.9% from the third quarter of 2014. Third quarter 2015 industrial sales increased 0.7% compared to the third quarter of 2014 primarily due to increased sales to customers in oil and gas related sectors. Weather-normalized commercial and residential sales increased 1.3% and 0.8% in the third quarter of 2015, respectively, from the third quarter of 2014.
AEP's weather-normalized retail sales volumes for the nine months ended September 30, 2015 increased 0.1% compared to the nine months ended September 30, 2014. Industrial sales volumes increased 0.8% compared to 2014, while weather-normalized commercial sales increased by 1.0%. Weather-normalized residential sales decreased 1.1% in comparison to the first nine months of 2014.
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, rules governing the beneficial use and disposal of coal combustion products, proposed and final 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 2014 Annual Report.  Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If the costs of environmental compliance are not recovered, it would reduce future net income and cash flows and impact financial condition.


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Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of September 30, 2015, the AEP System had a total generating capacity of approximately 32,100 MWs, of which approximately 18,200 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
 
880

 
950

Total
 
$
1,830

 
$
2,050


For APCo, the projected environmental investment above includes the conversion of 470 MWs of coal generation to natural gas capacity. 

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.

In May 2015, management retired the following plants or units of plants:

 
 
 
 
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

Total
 
 
 
2,565


As of September 30, 2015, the book value of the regulated plants in the table above has been approved for recovery, except for $147 million which is pending regulatory approval.


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Subject to the factors listed above and based upon continuing evaluation, management intends to retire the following units of plants during 2016:
 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs)
PSO
 
Northeastern Station, Unit 4
 
470

SWEPCo
 
Welsh Plant, Unit 2
 
528

Total
 
 
 
998


As of September 30, 2015, the net book value of the PSO and SWEPCo units listed above before cost of removal, including related materials and supplies inventory and CWIP balances, was $177 million. 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 Northeastern Station, Unit 4 and Welsh Plant, Unit 2, management is seeking regulatory recovery of remaining net book values.

Management is in the process of obtaining permits following the Virginia SCC and WVPSC's approval for the conversion of APCo's 470 MW Clinch River Plant, Units 1 and 2 to natural gas. In September 2015, management retired the coal-related assets of Clinch River Plant, Units 1 and 2. Of the coal-related assets retired in September 2015, $14 million is pending regulatory approval. Management expects to begin operations as a natural gas unit in the first quarter of 2016 for Clinch River Plant, Unit 1 and the second quarter of 2016 for Clinch River Plant, Unit 2. As of September 30, 2015, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of Clinch River Plant, Units 1 and 2 was $148 million.

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.  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 and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit.  The U.S. Court of Appeals for the District of Columbia Circuit ordered CSAPR to take effect on January 1, 2015 while the remand proceeding was still pending. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit remanded the rule to the Federal EPA. All of the states in which the Registrant Subsidiaries' power plants are located are covered by CSAPR. 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) will 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 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.  In March 2012, the Federal EPA disapproved certain portions of the Arkansas regional haze SIP. In April 2015, the Federal EPA published a proposed FIP to replace the disapproved

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portions, including revised BART determinations for the Flint Creek Plant that are consistent with the environmental controls currently under construction. 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 July 2015, management submitted comments to the proposed Arkansas FIP and participate in comments filed by industry associations of which the AEP System is a member. Management supports compliance with CSAPR programs as satisfaction of the BART requirements.

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.  This rule was overturned by the U.S. Supreme Court. The Federal EPA proposed to include CO2 emissions in standards that apply to new and existing electric utility units. See "Climate Change, CO2 Regulation and Energy Policy" section below.

The Federal EPA also issued new, more stringent national ambient air quality standards (NAAQS) for PM, SO2 and ozone. In October 2015, the Federal EPA announced a lower final NAAQS for ozone of 70 parts per billion. States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for facilities as a result of those evaluations. Management cannot currently predict the nature, stringency or timing of those requirements.

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

Cross-State Air Pollution Rule (CSAPR)

In 2011, the Federal EPA issued CSAPR.  Certain revisions to the rule were finalized in 2012.  CSAPR relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states.  Interstate trading of allowances is allowed on a restricted sub-regional basis.  Arkansas and Louisiana are subject only to the seasonal NOx program in the rule.  Texas is subject to the 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.  In 2012, the court issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing 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 petition for 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 Federal EPA 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. The court granted the Federal EPA's motion. The parties filed briefs and presented oral arguments. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit found that the Federal EPA over-controlled the SO2 and/or NOx budgets of 14 states. The U.S. Court of Appeals for the

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District of Columbia Circuit remanded the rule to the Federal EPA to timely revise the rule consistent with the court’s opinion while CSAPR remains in place. The Federal EPA is reviewing the decision and will take further action once their review is complete. Separate appeals of the Error Corrections Rule and the further revisions were filed but no briefing schedules have been established.

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 units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of nonmercury metals) and hydrogen chloride (as a surrogate for acid gases).  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 was required within three years. The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and the revised rule provides alternative work practice standards for operators during start-up and shut down periods.  Management has 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. Management remains concerned about the availability of compliance extensions, the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines and the lack of coordination among the Mercury and Air Toxics Standards (MATS) schedule and other environmental requirements.

Petitions for administrative reconsideration and judicial review of the final rule 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. A final rule on reconsideration was issued in 2014 and a proposed rule containing technical corrections was issued in early 2015. 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 trade groups and several states filed petitions for further review in the U.S. Supreme Court and the court granted those petitions in November 2014.

In June 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit and remanded the MATS rule for further proceedings consistent with its decision that the Federal EPA was unreasonable in refusing to consider costs in its determination whether to regulate emissions of HAPs from power plants. The case has been remanded to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings consistent with the U.S. Supreme Court’s decision. Management will continue to evaluate the impact of this decision and until further action by the U.S. Court of Appeals for the District of Columbia Circuit, the rule remains in place.

Climate Change, CO2 Regulation and Energy Policy

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 have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions.  The Registrant Subsidiaries are taking steps to comply with these requirements, including increasing wind power purchases and broadening the AEP System's portfolio of energy efficiency programs.

In the absence of comprehensive federal climate change or energy policy legislation, 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 under the CAA.  The new proposal was issued in September 2013 and requires new large natural gas units to meet a limit of 1,000 pounds of CO2 per MWh of electricity generated and small natural gas units to meet a limit of 1,100 pounds of CO2 per MWh.  New coal-fired units are required to meet a limit of 1,100 pounds of CO2 per MWh, with the option to meet a 1,000 pound per MWh limit if they choose to average emissions over multiple years.

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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 plans implementing the guidelines no later than June 2016.

In August 2015, the Federal EPA announced the final standards for new, modified and reconstructed fossil fired steam generating units and combustion turbines, guidelines for the development of state plans to regulate CO2 emissions from existing sources and proposed two options for a federal plan. The rules will become effective 60 days following publication. The final standard for new combustion turbines is 1,000 pounds of CO2 per MWh and the final standard for new fossil steam units is 1,400 pounds of CO2 per MWh. Reconstructed turbines are subject to the same standard as new units and no standard for modified combustion turbines was issued. Reconstructed fossil steam units are subject to a standard of 1,800 pounds of CO2 per MWh for larger units and 2,000 pounds of CO2 per MWh for smaller units. Modified fossil steam units will be subject to a site specific standard no lower than the standards that would be applied if the units were reconstructed.

The final emissions guidelines for existing sources are based on a series of declining performance standards that are implemented beginning in 2022 through 2029. Affected units must achieve a standard of 771 pounds of CO2 per MWh for existing natural gas combined cycle units and 1,305 pounds of CO2 per MWh for existing fossil steam units by 2030. The Federal EPA also developed a set of rate-based and mass-based state goals and has proposed “model” rules that can be adopted by the states that would allow sources within “trading ready” state programs to trade, bank or sell allowances or credits issued by the states or Federal EPA. The Federal EPA intends to finalize either a rate-based or mass-based trading program that can be enforced in states that fail to submit approved plans by the deadlines established in the final guidelines. States are required to submit final plans or an extension request by September 2016 to the Federal EPA. States receiving an extension request must submit final plans by September 2018. Management is reviewing the pre-publication version of the final rule and evaluating the rule’s impacts as well as the anticipated actions by states where assets are located. The final rule was already challenged in the courts and management expects additional lawsuits once the rule is published in the Federal Register.

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 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 (BACT) analysis for CO2 emissions if they exceed a reasonable level. The Federal EPA removed those provisions of the final rule from the Code of Federal Regulations that were inconsistent with the U.S. Supreme Court’s decision but continues to apply a 75,000 ton per year threshold to trigger the need for a BACT analysis. Petitions were filed with the U.S. Court of Appeals for the District of Columbia Circuit seeking to amend the judgment in the case to require Federal EPA to establish a reasonable minimum level. Those petitions were denied.

Federal and state legislation or regulations that mandate limits on the emission of CO2 could 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.

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 (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants.  The proposed rule contained two alternative proposals.  One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management.  Both proposals would impose stringent requirements for the construction of new coal ash landfills and existing unlined surface impoundments.

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In the final rule, the Federal EPA elected to regulate CCR as a non-hazardous solid waste and issued new minimum federal solid waste management standards. On the effective date, the rule applies to new and existing active CCR landfills and CCR surface impoundments at operating electric utility or independent power production facilities. The rule imposes new and additional construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements. The rule does not apply to inactive CCR landfills and inactive surface impoundments at retired generating stations or the beneficial use of CCR. The rule is self-implementing so state action is not required. Because of this self-implementing feature, the rule contains extensive record keeping, notice and internet posting requirements. Because the Registrant Subsidiaries currently use surface impoundments and landfills to manage CCR materials at the generating facilities, they will incur significant costs to upgrade or close and replace these existing facilities at some point in the future as the new rule is implemented.

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.  Encapsulated beneficial uses are not materially impacted by the new rule but additional demonstrations may be required to continue land applications in significant amounts except in road construction projects.

The final rule was published in the Federal Register in April 2015 and becomes effective six months after publication. The final rule provides for a staggered compliance schedule for the implementation of the rule’s many requirements. Management recorded a $45 million increase in asset retirement obligations in the second quarter of 2015 primarily due to the publication of the final rule. Given the schedule for implementation, management will continue to evaluate the rule's impact on operations.

Clean Water Act (CWA) Regulations

In 2014, the Federal EPA issued a final rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The final rule 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 were filed by industry and environmental groups and are currently pending in the U.S. Court of Appeals for the Second Circuit.

In addition, the Federal EPA developed revised effluent limitation guidelines for electricity generating facilities.  A pre-publication copy of the final rule was announced and made available in September 2015. In addition to other requirements, in the final rule the Federal EPA establishes limits on flue gas desulfurization wastewater, zero discharge for fly ash and bottom ash transport water and flue gas mercury control wastewater. Compliance with the final rule is as soon as possible after November 2018 and no later than December 2023. These new requirements will be implemented through each facility’s wastewater discharge permit. Management will continue to review the final rule 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.

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In June 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This jurisdictional definition applies 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. The final definition continues to recognize traditional navigable waters of the U.S. as jurisdictional as well as certain exclusions. The rule also contains a number of new specific definitions and criteria for determining whether certain other waters are jurisdictional because of a “significant nexus." Management believes that clarity and efficiency in the permitting process is needed. Management remains concerned that the rule introduces new concepts and could subject more of the operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. The final rule is being challenged in both courts of appeal and district courts. Challengers include industry associations of which the AEP System is a member. The U.S. Court of Appeal for the Sixth Circuit has granted a nationwide stay of the rule pending jurisdictional determinations.

ACCOUNTING PRONOUNCEMENTS

New Accounting Pronouncements Adopted During the First Quarter of 2015

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. Management adopted ASU 2014-08 effective January 1, 2015. There were no events requiring application of the new accounting guidance.

Pronouncements Effective in the Future

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, determine 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 FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted for 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, 2018.

The FASB issued ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. Management plans to adopt ASU 2015-01 effective January 1, 2016.

The FASB issued ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” to simplify the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The Registrant Subsidiaries include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management intends to early adopt ASU 2015-03 for the 2015 Form 10-K.

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The FASB issued ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-05 effective January 1, 2016.

The FASB issued ASU 2015-11 “Simplifying the Measurement of Inventory” to simplify the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-11 effective January 1, 2017.

The FASB issued ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. Management has analyzed the impact of this new standard and determined that it will have no impact on the accounting of the Registrant Subsidiaries' contracts. Additionally, adoption has no impact on net income. Management adopted ASU 2015-13 upon its issuance date.

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, consolidation policy and balance sheet classification of deferred taxes.  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 2015, 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, 2015, 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.


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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 2015 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.

Item 1A.  Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2014 includes a detailed discussion of risk factors.  As of September 30, 2015, there have been no material changes to the risk factors previously disclosed in the 2014 Annual Report on Form 10-K.

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, 2015.

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 22, 2015


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