10-Q 1 aep20152q10q.htm AMERICAN ELECTRIC POWER 2Q2015 10-Q AEP 2015 2Q 10Q


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended June 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
 
July 23, 2015
 
 
American Electric Power Company, Inc.
490,559,618

 
($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
June 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 3
 
 
 
 
Exhibit 10
 
 
 
 
Exhibit 12
 
 
 
 
Exhibit 31(a)
 
 
 
 
Exhibit 31(b)
 
 
 
 
Exhibit 32(a)
 
 
 
 
Exhibit 32(b)
 
 
 
 
Exhibit 95
 
 
 
 
Exhibit 101.INS
 
 
 
 
Exhibit 101.SCH
 
 
 
 
Exhibit 101.CAL
 
 
 
 
Exhibit 101.DEF
 
 
 
 
Exhibit 101.LAB
 
 
 
 
Exhibit 101.PRE
 
 
 
 
 
 
SIGNATURE
 
 
 
 
 
 
 
 
 
 
 
 
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.
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.
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.
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.

ii



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

iii



FORWARD-LOOKING INFORMATION

This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 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 of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
Ÿ
The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
Ÿ
Electric load, customer growth and the impact of 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 costs of and transportation for fuels and the creditworthiness and performance of fuel suppliers and transporters.
Ÿ
Availability of necessary generation capacity and the performance of our generation plants.
Ÿ
Our ability to recover 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 transition to market for generation in Ohio, including the implementation of ESPs and our ability to recover investments in our Ohio generation assets.

iv



Ÿ
Our ability to successfully and profitably manage our separate competitive generation assets.
Ÿ
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
Ÿ
Actions of rating agencies, including changes in the ratings of our debt.
Ÿ
The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.
Ÿ
Accounting pronouncements periodically issued by accounting standard-setting bodies.
Ÿ
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

The forward looking statements of AEP and its Registrant Subsidiaries speak only as of the date of this report or as of the date they are made.  AEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 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 second quarter of 2015 increased by 0.9% from the second quarter of 2014. Our second quarter 2015 industrial sales increased 0.6% compared to the second quarter of 2014 primarily due to increased sales to customers in oil and gas related sectors. Weather-normalized commercial and residential sales increased 1.9% and 0.3% in the second quarter of 2015, respectively, from the second quarter of 2014.
Our weather-normalized retail sales volumes for the six months ended June 30, 2015 decreased 0.3% compared to the six months ended June 30, 2014. Industrial sales volumes increased 0.9% compared to 2014, while weather-normalized commercial sales increased by 0.7%. Weather-normalized residential sales decreased 2.2% in comparison to the first six 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.

AEP River Operations Alternatives
AEP is evaluating strategic alternatives for its non-regulated AEP River Operations segment, which primarily includes commercial barging operations that transport liquids, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi rivers.  Potential alternatives may include, but are not limited to, continued ownership or a sale of the non-regulated river operations.  We have not made a decision regarding the potential alternatives, nor have we set a specific time frame for a decision.  We do not expect to incur a loss related to a potential sale transaction.
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 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.

1



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. If the Supreme Court of Ohio upholds its June 2015 order, it would remand the matter back to the PUCO for reinstatement of the weighted average cost of capital 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.

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 July 2014, OPCo submitted a separate application to continue the RSR to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00/MWh, until the balance of the capacity deferrals has been collected. In April 2015, the PUCO issued an order approving the application to continue the RSR, with modifications. In May 2015, the PUCO granted intervenors requests for rehearing. As of June 30, 2015, OPCo’s incurred deferred capacity costs balance was $432 million, including debt carrying costs.

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. As ordered, in 2014, OPCo conducted multiple energy-only auctions for a total of 100% of the SSO load with delivery beginning April 2014 through May 2015. As provided for in the June 2015 - May 2018 ESP, for delivery starting in June 2015, OPCo now conducts energy and capacity auctions for its entire SSO load. 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.

2



June 2015 - May 2018 ESP

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 included a return on common equity of 10.65% on capital costs for certain riders. 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 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 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, on rehearing, the PUCO issued an order that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In June 2015, OPCo and various intervenors filed applications for rehearing with the PUCO related to the May 2015 order on rehearing. In July 2015, the PUCO granted the requests for rehearing.

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) continued to include the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units.

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 is approximately $52 million.  In May 2014, intervenors filed appeals of the order with the Texas District Court.  In June 2014, SWEPCo intervened in those appeals and filed initial responses.  If certain parts of the PUCT order are overturned it could reduce future net income and cash flows and impact financial condition. See the “2012 Texas Base Rate Case” section of Note 4.

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.

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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 for 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 equity of 10.5% and is proposed to be effective in January 2016, except for the $44 million for environmental investments, which is proposed to be effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. In addition, the filing also notified the OCC that future incremental purchased capacity and energy costs of an estimated $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. 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.

2014 West Virginia Base Rate Case

In June 2014, APCo and WPCo filed a request with the WVPSC to increase annual base rates by $181 million to be effective in the second quarter of 2015.  The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units.  The filing also requested recovery of $89 million in regulatory assets over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs.  The filing also included a request to implement a rider of approximately $45 million annually to recover vegetation management costs, including a return on capital investment. 

In May 2015, the WVPSC issued an order on the 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. 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 weighted average cost of capital rate for the $25 million annual 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. See the “2014 West Virginia Base Rate Case” section of Note 4.

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 impairments related to new carbon emission guidelines issued by the Federal EPA.


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Kentucky Fuel Adjustment Clause Review

In August 2014, the KPSC issued an order initiating a review of KPCo's FAC from November 2013 through April 2014. 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 April 2015, the Franklin County Circuit Court issued an order approving intervenors' requests to hold this case in abeyance until the KPSC issues a final order in KPCo’s two-year FAC review case for the period November 2012 through October 2014. See the “Kentucky Fuel Adjustment Clause Review” section of Note 4.

2014 Kentucky Base Rate Case

In December 2014, KPCo filed a request with the KPSC for a net increase in rates of $70 million, which consists of a $75 million increase in rider rates, offset by a $5 million decrease in annual base rates, to be effective July 2015. 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. 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 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 for November 2012 through October 2014.

In June 2015, the KPSC issued an order that approved a modified stipulation agreement. The order approved a net revenue increase of $45 million 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. Once this order becomes final and non-appealable, KPCo will withdraw its appeal of the KPSC order in the KPCo fuel adjustment clause review. See "Kentucky Fuel Adjustment Clause Review" section above. See the “2014 Kentucky Base Rate Case” section of 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.  AGR’s excess capacity was subject to the PJM RPM auction. After May 2015, AGR's generation assets are subject to PJM capacity prices.  Shown below are the base RPM results through the June 2017 through May 2018 period:
 
 
PJM Base
PJM Auction Period
 
Auction Price
 
 
(per MW day)
June 2013 through May 2014
 
$
27.73

June 2014 through May 2015
 
125.99

June 2015 through May 2016
 
136.00

June 2016 through May 2017
 
59.37

June 2017 through May 2018
 
120.00


Management expects a significant decline in AGR capacity revenues after May 2015 because the Power Supply Agreement between AGR and OPCo ended. Management also expects a further decline in AGR capacity revenues from June 2016 through May 2017 based upon the RPM results.

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FERC has previously accepted incremental improvements relating to the PJM RPM auction including: (a) assuring that capacity imports have firm transmission, (b) placing limits on the number of MWs of summer-only demand response, (c) modification and enforcement of the dispatch of demand response to better reflect real-time capacity requirements, and (d) redesigning the RPM demand curve. Collectively, these improvements should reduce capacity price volatility and improve reliability.

In December 2014, PJM filed with FERC for approval of a new type of capacity product, the Capacity Performance Product (CP), intended to improve generator performance and reliability during emergency events by: (a) assessing higher penalties for non-performance during emergency events, (b) allowing higher offers into the auction and (c) requiring generators to provide assurances that they can perform reliably during emergency events.

In June 2015, FERC issued an order accepting most of PJM’s recommendations, including: (a) non-performance assessments based on the calculated cost of new entry, (b) capacity offers up to approximately $250/MW day for the June 2018 through May 2019 period without mitigation, (c) significant authority to review capacity offers for compliance with CP criteria, and (d) supplemental CP auctions for the June 2016 through May 2017, and June 2017 through May 2018 periods. These supplemental auctions address capacity performance and reliability issues in these interim years, and allow generators to re-offer at a higher price for capacity already cleared if they can perform as a CP resource. In July 2015, FERC issued a revision to its order, allowing demand response providers to participate in the supplemental auctions. The supplemental auctions for the June 2016 through May 2017 and June 2017 through May 2018 periods will take place during the third quarter of 2015.

FERC rejected AEP’s request for a full exemption from the CP rules for Fixed Resource Requirement entities, but did allow an exemption for the June 2018 through May 2019 period. FERC also rejected PJM’s recommendation for a monthly stop-loss provision. AEP filed a rehearing request in July 2015, 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 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC. As of June 30, 2015, SWEPCo has incurred costs of $256 million, including AFUDC, and has remaining contractual construction obligations of $89 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 June 30, 2015, the net book value of Welsh Plant, Units 1 and 3 was $484 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. In July 2015, the plaintiffs responded to the motion for partial judgment and simultaneously moved for partial summary judgment on their claims for breach of the lease and participation agreement. 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 June 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. If natural gas conversion is not completed, the units could be retired sooner than planned.

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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 June 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 was $752 million. Of this amount, $608 million has been approved for recovery while $144 million 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 June 30, 2015, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of the regulated plants in the table above was $178 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.

In addition, we are in the process of obtaining permits following the KPSC's approval for the conversion of KPCo's 278 MW Big Sandy Plant, Unit 1 to natural gas.  As of June 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 $104 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.


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Clean Air Act Requirements

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

The Federal EPA issued the Clean Air Interstate Rule (CAIR) in 2005 requiring specific reductions in SO2 and NOx emissions from power plants.  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. 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 will submit 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 has 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 has also issued new, more stringent national ambient air quality standards (NAAQS) for PM, SO2 and is currently reviewing the NAAQS for ozone. States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for our facilities as a result of those evaluations. We cannot currently predict the nature, stringency or timing of those requirements.

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

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Cross-State Air Pollution Rule (CSAPR)

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

Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit.  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 have filed briefs, presented oral arguments and the case remains pending. Separate appeals of the Error Corrections Rule and the further revisions were filed but no briefing schedules have been established. We cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for 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.

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.


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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 will be 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

National public policy makers and regulators in the 11 states we serve have diverse views on climate change, carbon regulation and energy policy.  We are currently focused on responding to these emerging views with prudent actions across a range of plausible scenarios and outcomes.  We are active participants in both state and federal policy development to assure that any proposed new requirements are feasible and the economies of the states we serve are not placed at a competitive disadvantage.

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.  This proposal was published in the Federal Register in January 2014 and the comment period has closed.

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. The Federal EPA issued guidelines for the development of standards for existing sources in June 2014. The guidelines use a “portfolio” approach to reducing emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units, expanding renewable generation resources and increasing customer energy efficiency. Comments were due in December 2014. The Federal EPA also issued proposed regulations governing emissions of CO2 from modified and reconstructed EGUs in June 2014 and comments were due in October 2014. The standards for modified and reconstructed units include several options, including use of historic baselines or energy efficiency audits to establish source-specific CO2 emission rates or to limit CO2 emission rates which could be no less than 1,900 pounds per MWh at larger coal units and 2,100 pounds per MWh at smaller coal units. The Federal EPA announced in January 2015 that the schedule for finalizing its action on all of these rules will extend into the summer of 2015 and that it will develop and propose for public comment a model FIP that will be finalized for individual states that fail to submit a timely state plan to implement the existing source guidelines. We cannot currently predict the impact these programs may have on future resource plans or our existing generating fleet, but the costs may be substantial.

In 2012, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO2 emissions from new motor vehicles and its plan to phase in regulation of CO2 emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. In 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

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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 are pending.

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.

The final rule was published in the Federal Register in April 2015 and becomes effective six months after publication. 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 future effective date of the rule and 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

12



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

In April 2014, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a proposed rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases and published the proposed rule in the Federal Register. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This proposed jurisdictional definition applied to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are: permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. We submitted detailed comments to the Federal EPA in November 2014 and also participated in comments filed by various organizations of which we are members. In June 2015, the Federal EPA published the final rule that included a few changes from the proposal. The effective date of the rule is 60 days following publication. 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 agree that clarity and efficiency in the permitting process is needed. We are 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. We anticipate that the final rule will be challenged in the courts.


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.


14



The table below presents Earnings Attributable to AEP Common Shareholders by segment for the three and six months ended June 30, 2015 and 2014.
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Vertically Integrated Utilities
$
207

 
$
154

 
$
506

 
$
432

Transmission and Distribution Utilities
78

 
90

 
175

 
187

AEP Transmission Holdco
65

 
47

 
101

 
71

Generation & Marketing
82

 
98

 
269

 
261

AEP River Operations
1

 
3

 
12

 
6

Corporate and Other (a)
(3
)
 
(2
)
 
(4
)
 
(7
)
Earnings Attributable to AEP Common Shareholders
$
430

 
$
390

 
$
1,059

 
$
950

(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

Second Quarter of 2015 Compared to Second Quarter of 2014

Earnings Attributable to AEP Common Shareholders increased from $390 million in 2014 to $430 million in 2015 primarily due to:

Successful rate proceedings in various jurisdictions.
An increase in annual formula rate adjustments.
An increase in transmission investment which resulted in higher revenues and income.
A decrease in employee-related expenses.
Favorable retail, trading and marketing activity.

These increases were partially offset by:

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

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Earnings Attributable to AEP Common Shareholders increased from $1.0 billion in 2014 to $1.1 billion in 2015 primarily due to:

Successful rate proceedings in various jurisdictions.
An increase in annual formula rate adjustments.
An increase in transmission investment which resulted in higher revenues and income.
A decrease in employee-related expenses.
Favorable retail, trading and marketing activity.

These increases were partially offset by:

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

Our results of operations by operating segment are discussed below.

15



VERTICALLY INTEGRATED UTILITIES
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 Vertically Integrated Utilities
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Revenues
 
$
2,183

 
$
2,252

 
$
4,688

 
$
4,838

Fuel and Purchased Electricity
 
781

 
934

 
1,764

 
2,028

Gross Margin
 
1,402

 
1,318

 
2,924

 
2,810

Other Operation and Maintenance
 
615

 
618

 
1,191

 
1,194

Depreciation and Amortization
 
266

 
252

 
538

 
515

Taxes Other Than Income Taxes
 
94

 
87

 
191

 
183

Operating Income
 
427

 
361

 
1,004

 
918

Interest and Investment Income
 
2

 

 
3

 
1

Carrying Costs Income
 
3

 
2

 
5

 
1

Allowance for Equity Funds Used During Construction
 
16

 
11

 
30

 
21

Interest Expense
 
(131
)
 
(132
)
 
(262
)
 
(263
)
Income Before Income Tax Expense and Equity Earnings
 
317

 
242

 
780

 
678

Income Tax Expense
 
110

 
88

 
274

 
245

Equity Earnings of Unconsolidated Subsidiaries
 
1

 
1

 
2

 
1

Net Income
 
208

 
155

 
508

 
434

Net Income Attributable to Noncontrolling Interests
 
1

 
1

 
2

 
2

Earnings Attributable to AEP Common Shareholders
 
$
207

 
$
154

 
$
506

 
$
432


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

 
 

 
 

 
 

Residential
6,672

 
6,716

 
17,051

 
17,621

Commercial
6,296

 
6,122

 
12,307

 
12,237

Industrial
8,937

 
9,025

 
17,297

 
17,357

Miscellaneous
574

 
577

 
1,122

 
1,132

Total Retail
22,479

 
22,440

 
47,777

 
48,347

 
 
 
 
 
 
 
 
Wholesale (a)
5,903

 
8,602

 
14,171

 
18,786

(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 
 June 30,
 
Six Months Ended 
 June 30,
 
2015
 
2014
 
2015
 
2014
 
(in degree days)
Eastern Region
 

 
 

 
 

 
 

Actual  Heating (a)
93

 
118

 
2,138

 
2,246

Normal  Heating (b)
139

 
138

 
1,743

 
1,731

 
 
 
 
 
 
 
 
Actual  Cooling (c)
402

 
362

 
402

 
362

Normal  Cooling (b)
324

 
324

 
329

 
329

 
 
 
 
 
 
 
 
Western Region
 

 
 

 
 

 
 

Actual  Heating (a)
9

 
47

 
1,049

 
1,233

Normal  Heating (b)
34

 
33

 
911

 
920

 
 
 
 
 
 
 
 
Actual  Cooling (c)
704

 
674

 
718

 
680

Normal  Cooling (b)
693

 
686

 
716

 
710


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


17



Second Quarter of 2015 Compared to Second Quarter of 2014
Reconciliation of Second Quarter of 2014 to Second Quarter of 2015
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
 
 
 
Second Quarter of 2014
 
$
154

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
111

Off-system Sales
 
(23
)
Transmission Revenues
 
1

Other Revenues
 
(5
)
Total Change in Gross Margin
 
84

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
3

Depreciation and Amortization
 
(14
)
Taxes Other Than Income Taxes
 
(7
)
Interest and Investment Income
 
2

Carrying Costs Income
 
1

Allowance for Equity Funds Used During Construction
 
5

Interest Expense
 
1

Total Change in Expenses and Other
 
(9
)
 
 
 

Income Tax Expense
 
(22
)
 
 
 
Second Quarter of 2015
 
$
207


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 $111 million primarily due to the following:
The effect of successful rate proceedings in our service territories which include:
A $37 million increase for I&M primarily due to rate increases from Indiana rate riders and annual formula rate adjustments.
A $33 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.
An $18 million increase primarily due to rate increases in Virginia and West Virginia, offset by a decrease in annual formula rates.
A $7 million increase for PSO primarily due to revenue increases from rate riders.
For the increases described above, $14 million relate to riders/trackers which have corresponding increases in expense items below.    
Margins from Off-system Sales decreased $23 million primarily due to lower market prices and decreased sales volumes.
Other Revenues decreased $5 million primarily due to a decrease in River Transportation Division (RTD) barging resulting from reduced deliveries to the Rockport Plant. This decrease in RTD revenue has a corresponding decrease in Other Operation and Maintenance expenses for barging as discussed below.


18



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

Other Operation and Maintenance expenses decreased $3 million primarily due to the following:
A $16 million decrease in employee-related expenses.
A $15 million decrease in storm expenses and vegetation management expenses primarily in the APCo region.
A $4 million decrease in uncollectible accounts expense due to the establishment of a regulatory asset for recovery in the May 2015 West Virginia base case order.
These decreases were partially offset by:
A $13 million increase in nuclear expenses.
A $14 million increase in recoverable expenses, primarily including PJM expenses currently fully recovered in rate recovery riders/trackers partially offset by lower RTD barging costs.
A $5 million increase in SPP and PJM transmission services expenses.
Depreciation and Amortization expenses increased $14 million primarily due to overall higher depreciable base and amortization related to an advanced metering rider implemented in November 2014 in Oklahoma.
Taxes Other Than Income Taxes increased $7 million primarily due to an increase in property taxes.
Allowance for Equity Funds Used During Construction increased $5 million primarily due to increases in environmental construction and transmission projects.
Income Tax Expense increased $22 million primarily due an increase in pretax book income partially offset by the regulatory accounting treatment of state income taxes.

19



Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014
Reconciliation of Six Months Ended June 30, 2014 to Six Months Ended June 30, 2015
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
 
 
 
Six Months Ended June 30, 2014
 
$
432

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
212

Off-system Sales
 
(95
)
Transmission Revenues
 
1

Other Revenues
 
(4
)
Total Change in Gross Margin
 
114

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
3

Depreciation and Amortization
 
(23
)
Taxes Other Than Income Taxes
 
(8
)
Interest and Investment Income
 
2

Carrying Costs Income
 
4

Allowance for Equity Funds Used During Construction
 
9

Interest Expense
 
1

Total Change in Expenses and Other
 
(12
)
 
 
 

Income Tax Expense
 
(29
)
Equity Earnings
 
1

 
 
 
Six Months Ended June 30, 2015
 
$
506


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 $212 million primarily due to the following:
The effect of successful rate proceedings in our service territories which include:
A $68 million increase primarily due to rate increases in Virginia and West Virginia, including an adjustment due to the amended Virginia law affecting biennial reviews.
A $54 million increase for I&M primarily due to rate increases from Indiana rate riders and annual formula rate adjustments.
A $43 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 $16 million increase for PSO primarily due to revenue increases from rate riders.
For the increases described above, $47 million relate to riders/trackers which have corresponding increases in expense items below.
A $31 million decrease in PJM expenses net of recovery or offsets.
These increases were partially offset by:
A $34 million decrease in weather-normalized load primarily due to lower residential sales in the eastern region.
Margins from Off-system Sales decreased $95 million primarily due to lower market prices and decreased sales volumes.
Other Revenues decreased $4 million primarily due to a decrease in River Transportation Division (RTD) barging resulting from reduced deliveries to the Rockport Plant. This decrease in RTD revenue has a corresponding decrease in Other Operation and Maintenance expenses for barging as discussed below.

20



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

Other Operation and Maintenance expenses decreased $3 million primarily due to the following:
A $38 million decrease in employee-related expenses.
A $12 million decrease in storm expenses and vegetation management expenses primarily in the APCo region.
These decreases were partially offset by:
A $38 million increase in recoverable expenses, primarily including PJM expenses currently fully recovered in rate recovery riders/trackers partially offset by lower RTD barging costs.
A $7 million increase in PJM transmission services expenses.
Depreciation and Amortization expenses increased $23 million primarily due to overall higher depreciable base and amortization related to an advanced metering rider implemented in November 2014 in Oklahoma.
Taxes Other Than Income Taxes increased $8 million primarily due to an increase in property taxes.
Allowance for Equity Funds Used During Construction increased $9 million primarily due to increases in environmental construction and transmission projects.
Income Tax Expense increased $29 million primarily due an increase in pretax book income partially offset by the regulatory accounting treatment of state income taxes.

TRANSMISSION AND DISTRIBUTION UTILITIES
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Transmission and Distribution Utilities
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Revenues
 
$
1,061

 
$
1,134

 
$
2,331

 
$
2,349

Fuel and Purchased Electricity
 
270

 
343

 
691

 
746

Amortization of Generation Deferrals
 
36

 
25

 
67

 
56

Gross Margin
 
755

 
766

 
1,573

 
1,547

Other Operation and Maintenance
 
289

 
298

 
608

 
591

Depreciation and Amortization
 
170

 
156

 
338

 
317

Taxes Other Than Income Taxes
 
118

 
108

 
240

 
227

Operating Income
 
178

 
204

 
387

 
412

Interest and Investment Income
 
1

 
3

 
3

 
6

Carrying Costs Income
 
6

 
7

 
12

 
14

Allowance for Equity Funds Used During Construction
 
4

 
2

 
8

 
5

Interest Expense
 
(68
)
 
(72
)
 
(138
)
 
(142
)
Income Before Income Tax Expense
 
121

 
144

 
272

 
295

Income Tax Expense
 
43

 
54

 
97

 
108

Net Income
 
78

 
90

 
175

 
187

Net Income Attributable to Noncontrolling Interests
 

 

 

 

Earnings Attributable to AEP Common Shareholders
 
$
78

 
$
90

 
$
175

 
$
187



21



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

 
 

 
 

 
 

Residential
5,630

 
5,559

 
12,896

 
13,086

Commercial
6,372

 
6,314

 
12,287

 
12,216

Industrial
5,809

 
5,630

 
11,089

 
10,773

Miscellaneous
177

 
182

 
338

 
353

Total Retail (a)
17,988

 
17,685

 
36,610

 
36,428

 
 
 
 
 
 
 
 
Wholesale (b)
429

 
453

 
963

 
1,152


(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.  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 
 June 30,
 
Six Months Ended 
 June 30,
 
2015
 
2014
 
2015
 
2014
 
(in degree days)
Eastern Region
 

 
 

 
 

 
 

Actual  Heating (a)
137

 
130

 
2,575

 
2,539

Normal  Heating (b)
186

 
187

 
2,067

 
2,067

 
 
 
 
 
 
 
 
Actual  Cooling (c)
350

 
362

 
350

 
362

Normal  Cooling (b)
287

 
280

 
290

 
283

 
 
 
 
 
 
 
 
Western Region
 

 
 

 
 

 
 

Actual  Heating (a)

 
2

 
320

 
302

Normal  Heating (b)
4

 
4

 
192

 
200

 
 
 
 
 
 
 
 
Actual  Cooling (d)
863

 
872

 
904

 
942

Normal  Cooling (b)
917

 
904

 
1,026

 
1,012


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


22



Second Quarter of 2015 Compared to Second Quarter of 2014
Reconciliation of Second Quarter of 2014 to Second Quarter of 2015
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
 
 
 
Second Quarter of 2014
 
$
90

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
13

Off-system Sales
 
(5
)
Transmission Revenues
 
(25
)
Other Revenues
 
6

Total Change in Gross Margin
 
(11
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
9

Depreciation and Amortization
 
(14
)
Taxes Other Than Income Taxes
 
(10
)
Interest and Investment Income
 
(2
)
Carrying Costs Income
 
(1
)
Allowance for Equity Funds Used During Construction
 
2

Interest Expense
 
4

Total Change in Expenses and Other
 
(12
)
 
 
 

Income Tax Expense
 
11

 
 
 

Second Quarter of 2015
 
$
78


The major components of the decrease 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 $13 million primarily due to the following:
A $14 million increase in transmission rider and PJM retail revenues primarily due to CRES transmission revenue collected through a non-bypassable retail transmission rider beginning in June 2015, which is partially offset by a corresponding decrease in Transmission Revenues below.
A $7 million increase in revenues associated with the Ohio Distribution Investment Rider (DIR).
A $6 million increase in TCC and TNC revenues primarily due to the recovery of ERCOT transmission expenses, which is offset in Other Operation and Maintenance expenses below.
A $4 million increase in industrial sales in Ohio.
These increases were partially offset by:
A $12 million decrease in revenues associated with the Ohio Storm Damage Recovery Rider which started in April 2014 and ended in April 2015. This decrease in Retail Margins is primarily offset by a decrease in Other Operation and Maintenance expenses below.
An $8 million decrease in the Energy Efficiency (EE), Peak Demand Reduction Cost Recovery Rider (PDR) revenues in Ohio. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
Margins from Off-system Sales decreased $5 million primarily due to lower margins on PJM liquidations on a legacy OPCo power contract and lower Oklaunion purchased power agreement (PPA) revenues.
Transmission Revenues decreased $25 million primarily due to:
A $12 million decrease in Ohio revenues related to a lower transmission formula rate true-up than in the prior year.
A $10 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

23



responsibility of the CRES providers prior to June 2015, which is partially offset by a corresponding increase in Retail Margins above.
A $7 million OPCo transmission regulatory loss provision in 2015.
These decreases were partially offset by:
A $7 million increase primarily due to increased transmission investment in ERCOT.
Other Revenues increased $6 million primarily due to $3 million of increased pole attachment revenue for OPCo and $2 million in Texas securitization revenues which is offset in Depreciation and Amortization below.

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:
A $12 million decrease due to the completion of the amortization of Ohio 2012 deferred storm expenses. This decrease was offset by a corresponding decrease in Retail Margins above.
An $8 million decrease in EE and PDR expenses. This decrease was offset by a corresponding decrease in Retail Margins above.
A $5 million decrease in employee-related expenses.
These decreases were partially offset by:
A $9 million increase in PJM and ERCOT transmission services expenses.
A $6 million increase in storm expenses primarily in the Texas region.
Depreciation and Amortization expenses increased $14 million primarily due to the following:
An $8 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, which is partially offset in Other Revenues.
Taxes Other Than Income Taxes increased $10 million primarily due to an increase in property taxes.
Interest Expense decreased $4 million primarily due to reduced TCC long-term debt outstanding, which is partially offset in Other Revenues.
Income Tax Expense decreased $11 million primarily due to a decrease in pretax book income and the regulatory accounting treatment of state income taxes.


24



Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014
Reconciliation of Six Months Ended June 30, 2014 to Six Months Ended June 30, 2015
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
 
 
 
Six Months Ended June 30, 2014
 
$
187

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
44

Off-system Sales
 
(4
)
Transmission Revenues
 
(21
)
Other Revenues
 
7

Total Change in Gross Margin
 
26

 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(17
)
Depreciation and Amortization
 
(21
)
Taxes Other Than Income Taxes
 
(13
)
Interest and Investment Income
 
(3
)
Carrying Costs Income
 
(2
)
Allowance for Equity Funds Used During Construction
 
3

Interest Expense
 
4

Total Change in Expenses and Other
 
(49
)
 
 
 

Income Tax Expense
 
11

 
 
 

Six Months Ended June 30, 2015
 
$
175


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 $44 million primarily due to the following:
A $23 million increase in TCC and TNC revenues primarily due to the recovery of ERCOT transmission expenses, which is offset in Other Operation and Maintenance expenses below.
A $15 million increase in revenues associated with the Ohio Distribution Investment Rider (DIR).
A $14 million increase in transmission rider and PJM retail revenues primarily due to CRES transmission revenue collected through a non-bypassable retail transmission rider beginning in June 2015, which is partially offset by a corresponding decrease in Transmission Revenues below.
A $10 million increase in Ohio base rates due to the discontinuance of seasonal rates.
These increases were partially offset by:
A $17 million decrease in the Energy Efficiency (EE), Peak Demand Reduction Cost Recovery Rider (PDR) revenues in Ohio. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
Margins from Off-system Sales decreased $4 million primarily due to lower margins on PJM liquidations on a legacy OPCo power contract and lower Oklaunion PPA revenues.
Transmission Revenues decreased $21 million primarily due to:
A $12 million decrease in Ohio revenues related to a lower transmission formula rate true-up than in the prior year.
A $10 million decrease in 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, which is partially offset by a corresponding increase in Retail Margins above.
A $7 million OPCo transmission regulatory loss provision in 2015.
These decreases were partially offset by:

25



An $11 million increase primarily due to increased transmission investment in ERCOT.
Other Revenues increased $7 million primarily due to $4 million of increased pole attachment revenue for OPCo and a $2 million increase in Texas securitization revenues which is offset in Depreciation and Amortization below.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $17 million primarily due to the following:
A $17 million increase in recoverable ERCOT transmission expenses currently recovered dollar-for-dollar in rate recovery riders/trackers.
A $14 million increase in PJM transmission services expenses.
A $13 million increase in distribution expenses including system improvements and storm expenses.
A $6 million increase due to PUCO ordered contributions to the Ohio Growth Fund.
These increases were partially offset by:
A $17 million decrease in EE and PDR costs and associated deferrals. This decrease was offset by a corresponding decrease in Retail Margins above.
An $11 million decrease in employee-related expenses.
Depreciation and Amortization expenses increased $21 million primarily due to the following:
A $12 million increase due to an increase in the depreciable base of transmission and distribution assets.
A $7 million increase in amortization of TCC's securitization transition asset, which is partially offset in Other Revenues.
Taxes Other Than Income Taxes increased $13 million primarily due to increased property taxes.
Interest Expense decreased $4 million primarily due to reduced TCC long-term debt outstanding, which is partially offset in Other Revenues.
Income Tax Expense decreased $11 million primarily due to a decrease in pretax book income and by the regulatory accounting treatment of state income taxes.

26



AEP TRANSMISSION HOLDCO
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
AEP Transmission Holdco
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Transmission Revenues
 
$
99

 
$
57

 
$
157

 
$
85

Other Operation and Maintenance
 
8

 
6

 
16

 
11

Depreciation and Amortization
 
9

 
6

 
18

 
11

Taxes Other Than Income Taxes
 
17

 
6

 
33

 
13

Operating Income
 
65

 
39

 
90

 
50

Allowance for Equity Funds Used During Construction
 
14

 
12

 
26

 
21

Interest Expense
 
(9
)
 
(5
)
 
(17
)
 
(10
)
Income Before Income Tax Expense and Equity Earnings
 
70

 
46

 
99

 
61

Income Tax Expense
 
29

 
22

 
43

 
30

Equity Earnings of Unconsolidated Subsidiaries
 
24

 
23

 
46

 
40

Net Income
 
65

 
47

 
102

 
71

Net Income Attributable to Noncontrolling Interests
 

 

 
1

 

Earnings Attributable to AEP Common Shareholders
 
$
65

 
$
47

 
$
101

 
$
71



Summary of Net Plant in Service and CWIP for AEP Transmission Holdco
 
 
As of June 30,
 
 
2015
 
2014
 
 
(in millions)
Net Plant in Service
 
$
2,111

 
$
1,167

CWIP
 
1,130

 
895


27



Second Quarter of 2015 Compared to Second Quarter of 2014
 
Reconciliation of Second Quarter of 2014 to Second Quarter of 2015
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Second Quarter of 2014
 
$
47

 
 
 
Changes in Transmission Revenues:
 
 
Transmission Revenues
 
42

Total Change in Transmission Revenues
 
42

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(2
)
Depreciation and Amortization
 
(3
)
Taxes Other Than Income Taxes
 
(11
)
Allowance for Equity Funds Used During Construction
 
2

Interest Expense
 
(4
)
Total Change in Expenses and Other
 
(18
)
 
 
 
Income Tax Expense
 
(7
)
Equity Earnings
 
1

 
 
 
Second Quarter of 2015
 
$
65


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 $42 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 $2 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $3 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $11 million primarily due to increased property taxes.
Allowance for Equity Funds Used During Construction increased $2 million primarily due to increased transmission investment.
Interest Expense increased $4 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $7 million primarily due to an increase in pretax book income.


28



Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014
 
Reconciliation of Six Months Ended June 30, 2014 to Six Months Ended June 30, 2015
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Six Months Ended June 30, 2014
 
$
71

 
 
 
Changes in Transmission Revenues:
 
 
Transmission Revenues
 
72

Total Change in Transmission Revenues
 
72

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(5
)
Depreciation and Amortization
 
(7
)
Taxes Other Than Income Taxes
 
(20
)
Allowance for Equity Funds Used During Construction
 
5

Interest Expense
 
(7
)
Total Change in Expenses and Other
 
(34
)
 
 
 
Income Tax Expense
 
(13
)
Equity Earnings
 
6

Net Income Attributable to Noncontrolling Interests
 
(1
)
 
 
 
Six Months Ended June 30, 2015
 
$
101


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 $72 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 $5 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $7 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $20 million primarily due to increased property taxes.
Allowance for Equity Funds Used During Construction increased $5 million primarily due to increased transmission investment.
Interest Expense increased $7 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $13 million primarily due to an increase in pretax book income.
Equity Earnings increased $6 million primarily due to increased transmission investment by ETT.


29



GENERATION & MARKETING
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Generation & Marketing
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Revenues
 
$
801

 
$
913

 
$
1,971

 
$
2,164

Fuel, Purchased Electricity and Other
 
491

 
560

 
1,207

 
1,365

Gross Margin
 
310

 
353

 
764

 
799

Other Operation and Maintenance
 
116

 
125

 
216

 
241

Depreciation and Amortization
 
51

 
56

 
101

 
113

Taxes Other Than Income Taxes
 
11

 
13

 
20

 
25

Operating Income
 
132

 
159

 
427

 
420

Interest and Investment Income
 
1

 
1

 
2

 
2

Interest Expense
 
(10
)
 
(11
)
 
(21
)
 
(23
)
Income Before Income Tax Expense
 
123

 
149

 
408

 
399

Income Tax Expense
 
41

 
51

 
139

 
138

Net Income
 
82

 
98

 
269

 
261

Net Income Attributable to Noncontrolling Interests
 

 

 

 

Earnings Attributable to AEP Common Shareholders
 
$
82

 
$
98

 
$
269

 
$
261



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

 
 

 
 

 
 

Coal
6

 
9

 
16

 
21

Natural Gas
3

 
2

 
7

 
4

Total MWhs
9

 
11

 
23

 
25



30



Second Quarter of 2015 Compared to Second Quarter of 2014
Reconciliation of Second Quarter of 2014 to Second Quarter of 2015
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
 
 
 
Second Quarter of 2014
 
$
98

 
 
 

Changes in Gross Margin:
 
 

Generation
 
(53
)
Retail, Trading and Marketing
 
12

Other
 
(2
)
Total Change in Gross Margin
 
(43
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
9

Depreciation and Amortization
 
5

Taxes Other Than Income Taxes
 
2

Interest Expense
 
1

Total Change in Expenses and Other
 
17

 
 
 

Income Tax Expense
 
10

 
 
 

Second Quarter of 2015
 
$
82


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 $53 million primarily due to lower capacity revenue due to the termination of the Power Supply Agreement between AGR and OPCo.
Retail, Trading and Marketing increased $12 million primarily due to an increase in retail volumes.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses decreased $9 million primarily due to a decrease in plant outage and maintenance costs.
Depreciation and Amortization expenses decreased $5 million primarily due to reduced plant in service.
Income Tax Expense decreased $10 million primarily due to a decrease in pretax book income.


31



Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014
Reconciliation of Six Months Ended June 30, 2014 to Six Months Ended June 30, 2015
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
 
 
 
Six Months Ended June 30, 2014
 
$
261

 
 
 

Changes in Gross Margin:
 
 

Generation
 
(77
)
Retail, Trading and Marketing
 
46

Other
 
(4
)
Total Change in Gross Margin
 
(35
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
25

Depreciation and Amortization
 
12

Taxes Other Than Income Taxes
 
5

Interest Expense
 
2

Total Change in Expenses and Other
 
44

 
 
 

Income Tax Expense
 
(1
)
 
 
 

Six Months Ended June 30, 2015
 
$
269


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 $77 million primarily due to lower capacity revenue due to the termination of the Power Supply Agreement between AGR and OPCo.
Retail, Trading and Marketing increased $46 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 $25 million primarily due to a decrease in plant outage and maintenance costs.
Depreciation and Amortization expenses decreased $12 million primarily due to reduced plant in service.
Taxes Other Than Income Taxes decreased $5 million primarily due to a decrease in property taxes.


32