EX-13 10 aep10kfrex1320164q.htm ANNUAL REPORT Exhibit


2016 Annual Reports

American Electric Power Company, Inc. and Subsidiary Companies
Appalachian Power Company and Subsidiaries
Indiana Michigan Power Company and Subsidiaries
Ohio Power Company and Subsidiaries
Public Service Company of Oklahoma
Southwestern Electric Power Company Consolidated









Audited Financial Statements and
Management’s Discussion and Analysis of Financial Condition and Results of Operations












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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF ANNUAL REPORTS
 
 
Page
Number
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Management’s Report on Internal Control Over Financial Reporting
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Management’s Report on Internal Control Over Financial Reporting
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Management’s Report on Internal Control Over Financial Reporting
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Management’s Report on Internal Control Over Financial Reporting
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Management’s Report on Internal Control Over Financial Reporting
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Management’s Report on Internal Control Over Financial Reporting
 
 
 
 
 
 
 
 
 



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
 
American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit
 
AEP Credit, Inc., a consolidated variable interest entity of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East Companies
 
APCo, I&M, KPCo and OPCo.
AEP Energy
 
AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.
AEP Renewables
 
AEP Renewables, LLC, a wholly-owned subsidiary of Energy Supply and a consolidated variable interest entity formed for the purpose of providing utility scale wind and solar projects whose power output is sold via long-term power purchase agreements to other utilities, cities and corporations.
AEP System
 
American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP Texas
 
AEP Texas Inc., an AEP electric utility subsidiary.
AEP Transmission Holdco
 
AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEPEP
 
AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in the deregulated Ohio and Texas market.
AEPRO
 
AEP River Operations, LLC.
AEPSC
 
American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEP Utilities
 
AEP Utilities, Inc., a former subsidiary of AEP and holding company for TCC, TNC and CSW Energy, Inc.  Effective December 31, 2016, TCC and TNC were merged into AEP Utilities, Inc.  Subsequently following this merger, the assets and liabilities of CSW Energy, Inc. were transferred to an affiliated company and AEP Utilities, Inc. was renamed AEP Texas Inc.
AFUDC
 
Allowance for Funds Used During Construction.
AGR
 
AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.
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.

i


Term
 
Meaning
 
 
 
DCC Fuel
 
DCC Fuel VI LLC, DCC Fuel VII, DCC Fuel VIII, DCC Fuel IX and DCC X, consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
Desert Sky
 
Desert Sky Wind Farm, a 160.5 MW wind electricity generation facility located on Indian Mesa in Pecos County, Texas.
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 Cost.
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.
ETT
 
Electric Transmission Texas, LLC, an equity interest joint venture between Parent 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.
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.
kV
 
Kilovolt.
KWh
 
Kilowatthour.
LPSC
 
Louisiana Public Service Commission.
MISO
 
Midwest Independent Transmission System Operator.
MLR
 
Member load ratio, the method used to allocate transactions among members of the Interconnection Agreement.
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.

ii


Term
 
Meaning
 
 
 
NSR
 
New Source Review.
OATT
 
Open Access Transmission Tariff.
OCC
 
Corporation Commission of the State of Oklahoma.
Ohio Phase-in-Recovery Funding
 
Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OPEB
 
Other Postretirement Benefit Plans.
Operating Agreement
 
Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third party sales.  AEPSC acts as the agent.
OTC
 
Over the counter.
OVEC
 
Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
Parent
 
American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PCA
 
Power Coordination Agreement among APCo, I&M, KPCo and WPCo.
PIRR
 
Phase-In Recovery Rider.
PJM
 
Pennsylvania – New Jersey – Maryland regional transmission organization.
PM
 
Particulate Matter.
PPA
 
Purchase Power and Sale Agreement.
Price River
 
Rights and interests in certain coal reserves located in Carbon County, Utah.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
Putnam
 
Rights and interests in certain coal reserves located in Putnam, Mason and Jackson Counties, West Virginia.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants: APCo, I&M, OPCo, PSO and SWEPCo.
Registrants
 
SEC registrants: AEP, APCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
 
A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.  AEGCo and I&M jointly-own Unit 1.  In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
RPM
 
Reliability Pricing Model.
RSR
 
Retail Stability Rider.
RTO
 
Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine
 
Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC
 
U.S. Securities and Exchange Commission.
SEET
 
Significantly Excessive Earnings Test.
SIA
 
System Integration Agreement, effective June 15, 2000, as amended, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF
 
Spent Nuclear Fuel.
SO2
 
Sulfur dioxide.
SPP
 
Southwest Power Pool regional transmission organization.
SSO
 
Standard service offer.
Stall Unit
 
J. Lamar Stall Unit at Arsenal Hill Plant, a 534 MW natural gas unit owned by SWEPCo.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC
 
Formerly AEP Texas Central Company; now a division of AEP Texas.

iii


Term
 
Meaning
 
 
 
Texas Restructuring Legislation
 
Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC
 
Formerly AEP Texas North Company; now a division of AEP Texas.
TRA
 
Tennessee Regulatory Authority.
Transition Funding
 
AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.
Transource Energy
 
Transource Energy, LLC, a consolidated variable interest entity formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.
Transource Missouri
 
A 100% wholly-owned subsidiary of Transource Energy.
Trent
 
Trent Wind Farm, a 150 MW wind electricity generation facility located between Abilene and Sweetwater in West Texas.
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.

iv


FORWARD-LOOKING INFORMATION

This report made by the Registrants 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,” 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, management undertakes 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
Economic growth or contraction within and changes in market demand and demographic patterns in AEP service territories.
Ÿ
Inflationary or deflationary interest rate trends.
Ÿ
Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
Ÿ
The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
Ÿ
Electric load and customer growth.
Ÿ
Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.
Ÿ
The cost of fuel and its transportation, the creditworthiness and performance of fuel suppliers and transporters and the cost of storing and disposing of used fuel, including coal ash and spent nuclear fuel.
Ÿ
Availability of necessary generation capacity and the performance of generation plants.
Ÿ
The ability to recover fuel and other energy costs through regulated or competitive electric rates.
Ÿ
The ability to build transmission lines and facilities (including the 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 that could impact the continued operation, cost recovery and/or profitability of 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
The ability to constrain operation and maintenance costs.
Ÿ
The ability to develop and execute a strategy based on a view regarding prices of electricity and gas.
Ÿ
Prices and demand for power generated and sold at wholesale.
Ÿ
Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
Ÿ
The ability to recover through rates 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.
Ÿ
Changes in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP.
Ÿ
The ability to successfully and profitably manage competitive generation assets, including the evaluation and execution of strategic alternatives for these assets as some of the alternatives could result in a loss.
Ÿ
Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.

v


Ÿ
Actions of rating agencies, including changes in the ratings of debt.
Ÿ
The impact of volatility in the capital markets on the value of the investments held by the 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 the Registrants speak only as of the date of this report or as of the date they are made.  The Registrants 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 this report.

Investors should note that the Registrants announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, the Registrants may use the Investors section of AEP’s website (www.aep.com) to communicate with investors about the Registrants. It is possible that the financial and other information posted there could be deemed to be material information. The information on AEP’s website is not part of this report.

vi


AEP COMMON STOCK AND DIVIDEND INFORMATION

The AEP common stock quarterly high and low sales prices, quarter-end closing price and the cash dividends paid per share are shown in the following table:
Quarter Ended
 
High
 
Low
 
Quarter-End
Closing Price
 
Dividend
December 31, 2016
 
$
65.25

 
$
57.89

 
$
62.96

 
$
0.59

September 30, 2016
 
71.32

 
63.56

 
64.21

 
0.56

June 30, 2016
 
70.10

 
61.42

 
70.09

 
0.56

March 31, 2016
 
66.49

 
56.75

 
66.40

 
0.56

 
 
 
 
 
 
 
 
 
December 31, 2015
 
$
59.52

 
$
53.30

 
$
58.27

 
$
0.56

September 30, 2015
 
59.18

 
52.29

 
56.86

 
0.53

June 30, 2015
 
58.35

 
52.32

 
52.97

 
0.53

March 31, 2015
 
65.38

 
54.66

 
56.25

 
0.53


AEP common stock is traded principally on the New York Stock Exchange.  As of December 31, 2016, AEP had approximately 66,000 registered shareholders.

performancegraph2016.jpg

vii



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
 
 
 
 
 
 
2016 (a)
 
2015
 
2014
 
2013
 
2012
 
 
(dollars in millions, except per share amounts)
STATEMENTS OF INCOME DATA
 
 
 
 
 
 
 
 
 
 
Total Revenues
 
$
16,380.1

 
$
16,453.2

 
$
16,378.6

 
$
14,813.5

 
$
14,298.4

 
 


 
 
 
 
 
 
 
 
Operating Income
 
$
1,207.1

 
$
3,333.5

 
$
3,127.4

 
$
2,822.5

 
$
2,620.7

Income from Continuing Operations
 
$
620.5

 
$
1,768.6

 
$
1,590.5

 
$
1,473.9

 
$
1,247.7

Income (Loss) From Discontinued Operations, Net of Tax
 
(2.5
)
 
283.7

 
47.5

 
10.3

 
14.5

Net Income
 
618.0

 
2,052.3

 
1,638.0

 
1,484.2

 
1,262.2

 
 
 
 
 
 
 
 
 
 
 
Net Income Attributable to Noncontrolling Interests
 
7.1

 
5.2

 
4.2

 
3.7

 
3.4

 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
610.9

 
$
2,047.1

 
$
1,633.8

 
$
1,480.5

 
$
1,258.8

 
 
 
 
 
 
 
 
 
 
 
BALANCE SHEETS DATA
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
 
$
62,036.6

 
$
65,481.4

 
$
63,605.9

 
$
59,646.7

 
$
56,817.4

Accumulated Depreciation and Amortization
 
16,397.3

 
19,348.2

 
19,970.8

 
19,098.6

 
18,529.6

Total Property, Plant and Equipment – Net
 
$
45,639.3

 
$
46,133.2

 
$
43,635.1

 
$
40,548.1

 
$
38,287.8

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
63,467.7

 
$
61,683.1

 
$
59,544.6

 
$
56,321.0

 
$
54,272.1

 
 


 
 
 
 
 
 
 
 
Total AEP Common Shareholders’ Equity
 
$
17,397.0

 
$
17,891.7

 
$
16,820.2

 
$
16,085.0

 
$
15,237.2

 
 


 
 
 
 
 
 
 
 
Noncontrolling Interests
 
$
23.1

 
$
13.2

 
$
4.3

 
$
0.8

 
$
0.4

 
 


 
 
 
 
 
 
 
 
Long-term Debt (b)
 
$
20,256.4

 
$
19,572.7

 
$
18,512.4

 
$
18,198.2

 
$
17,574.4

 
 


 
 
 
 
 
 
 
 
Obligations Under Capital Leases (b)
 
$
305.5

 
$
343.5

 
$
362.8

 
$
403.3

 
$
306.3

 
 


 
 
 
 
 
 
 
 
AEP COMMON STOCK DATA
 


 
 
 
 
 
 
 
 
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders:
 


 
 
 
 
 
 
 
 
 
 


 
 
 
 
 
 
 
 
From Continuing Operations
 
$
1.25

 
$
3.59

 
$
3.24

 
$
3.02

 
$
2.57

From Discontinued Operations
 
(0.01
)
 
0.58

 
0.10

 
0.02

 
0.03

 
 


 
 
 
 
 
 
 
 
Total Basic Earnings per Share Attributable to AEP Common Shareholders
 
$
1.24

 
$
4.17

 
$
3.34

 
$
3.04

 
$
2.60

 
 


 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares Outstanding (in millions)
 
491.5

 
490.3

 
488.6

 
486.6

 
484.7

 
 

 
 
 
 
 
 
 
 
Market Price Range:
 

 
 
 
 
 
 
 
 
High
 
$
71.32

 
$
65.38

 
$
63.22

 
$
51.60

 
$
45.41

Low
 
$
56.75

 
$
52.29

 
$
45.80

 
$
41.83

 
$
36.97

 
 


 
 
 
 
 
 
 
 
Year-end Market Price
 
$
62.96

 
$
58.27

 
$
60.72

 
$
46.74

 
$
42.68

 
 


 
 
 
 
 
 
 
 
Cash Dividends Declared per AEP Common Share
 
$
2.27

 
$
2.15

 
$
2.03

 
$
1.95

 
$
1.88

 
 


 
 
 
 
 
 
 
 
Dividend Payout Ratio
 
183.06
%
 
51.56
%
 
60.78
%
 
64.14
%
 
72.31
%
 
 


 
 
 
 
 
 
 
 
Book Value per AEP Common Share
 
$
35.38

 
$
36.44

 
$
34.37

 
$
32.98

 
$
31.35


(a)
The 2016 financial results include pretax asset impairments of $2.3 billion (see Note 7 to the financial statements).
(b)
Includes portion due within one year.

1


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

EXECUTIVE OVERVIEW

Company Overview

AEP is one of the largest investor-owned electric public utility holding companies in the United States.  AEP’s electric utility operating companies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia.

AEP’s subsidiaries operate an extensive portfolio of assets including:

Approximately 224,000 miles of distribution lines that deliver electricity to 5.4 million customers.
Approximately 40,000 miles of transmission lines, including 2,114 miles of 765 kV lines, the backbone of the electric interconnection grid in the Eastern United States.
AEP Transmission Holdco has approximately $4.4 billion of transmission assets in-service.
Approximately 31,000 megawatts of generating capacity in 3 RTOs as of December 31, 2016, one of the largest complements of generation in the United States. After the sale of certain generation assets in January 2017, AEP has approximately 26,000 megawatts of generating capacity.

Customer Demand

AEP’s weather-normalized retail sales volumes for the year ended December 31, 2016 decreased by 0.2% from the year ended December 31, 2015. AEP’s 2016 industrial sales volumes decreased 1.4% compared to 2015 primarily due to decreased sales to customers in the manufacturing sector. Weather-normalized residential sales volumes were flat and commercial sales increased by 0.9% in 2016, respectively, from 2015.

In 2017, AEP anticipates weather-normalized retail sales volumes will increase by 0.7%. The industrial class is expected to increase by 1.5% in 2017, primarily related to a number of new oil and natural gas expansions, especially around the major shale gas areas within AEP’s footprint. Weather-normalized residential sales volumes are projected to increase by 0.2%, primarily related to projected customer growth. Weather-normalized commercial sales volumes are projected to increase by 0.3%.

Ohio Global Settlement

In February 2017, the PUCO approved a settlement agreement (Global Settlement) filed by OPCo in December 2016. The parties to the Global Settlement include OPCo, the PUCO staff and various intervenors. The Global Settlement resolves all remaining open issues on remand from the Ohio Supreme Court in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings, including issues related to carrying charges on the PIRR and issues related to the RSR capacity charges. It also resolves all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits.

The significant components of the Global Settlement include:

Remands Related to the PIRR

All applicable parties participating in this settlement will withdraw their pending applications for rehearing of the PUCO order that allowed for the reinstatement of the equity portion of the weighted average cost of capital (WACC)
rate on previously deferred fuel balances. As part of the Global Settlement, the PIRR rate to be collected from customers through December 2018 will be reduced by $97 million.

2


Remands Related to the RSR

Beginning January 2017, OPCo will be entitled to collect $388 million in RSR revenues over a total of 30 months, subject to true up at the end of the collection period in June 2019. Current RSR rates will continue until the new RSR rates are approved. The Global Settlement resolves the issues related to the non-deferral portion of RSR collections and the impact of the appropriate energy credit on capacity charges. In December 2016, OPCo recorded an increase in Regulatory Assets on the balance sheets for the deferral of $83 million in RSR capacity costs and $14 million in related debt carrying charges with a corresponding decrease in expense in Generation Deferrals and an increase in Carrying Costs Income, respectively, on the statements of income.

For the year ended December 31, 2016, AEP recorded approximately $97 million in RSR capacity deferrals and related carrying charges to the following line items on the statements of income:
 
AEP
 
(in millions)
 
 
Fuel and Other Consumables Used for Electric Generation
$
(19.0
)
Purchased Electricity for Resale
(19.9
)
Other Operation
(15.7
)
Depreciation and Amortization
(42.1
)
Total Decrease in RSR Expenses
$
(96.7
)

As of December 31, 2016, OPCo’s total RSR under-recovery balance, including carrying charges, was $299 million.

Remands Related to the SEET

As part of the Global Settlement, $20 million will be returned to customers over a 12-month period commencing within 45 days of the final PUCO order adopting the Global Settlement. The Global Settlement states that this obligation has no precedential effect on OPCo’s SEET methodology. In addition, the parties agreed that earnings were not significantly excessive in 2015. In December 2016, OPCo accrued $20 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the issues related to the 2014 and 2015 SEET proceedings.

Fuel Adjustment Clause Proceedings

OPCo will refund $100 million paid by SSO customers from August 2012 - May 2015 related to OVEC and Lawrenceburg purchases. In December 2016, OPCo accrued $100 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the claimed recovery of fixed fuel costs through both the FAC and the approved capacity charges. This refund will be a one-time credit that will be applied the earlier of either 45 days after the final non-appealable order from the PUCO adopting the Global Settlement, or the December 2017 billing cycle.

Also see “OPCo Rate Matters” section of Note 4.

June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024

In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is subject to audit and review by the PUCO. Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider.

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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.

Merchant Generation Assets

In September 2016, AEP signed an agreement to sell Darby, Gavin, Lawrenceburg and Waterford Plants (“Disposition Plants”) totaling 5,329 MWs of competitive generation to a nonaffiliated party. As of December 31, 2016, the net book value of these assets, including related materials and supplies inventory and CWIP, was $1.8 billion. The sale closed in January 2017 for approximately $2.2 billion. The net proceeds from the transaction are approximately $1.2 billion in cash after taxes, repayment of debt associated with these assets and transaction fees, which resulted in an after tax gain of approximately $130 million. AEP plans to primarily use these proceeds to reduce outstanding debt and invest in its regulated businesses, including transmission and contracted renewable projects.

The assets and liabilities included in the sale transaction have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on the balance sheet as of December 31, 2016. See “Assets and Liabilities Held for Sale” section of Note 7 for additional information.

In September 2016, due to AEP’s ongoing evaluation of strategic alternatives for its merchant generation assets, declining forecasts of future energy and capacity prices, and a decreasing likelihood of cost recovery through regulatory proceedings or legislation in the state of Ohio providing for the recovery of AEP’s existing Ohio merchant generation assets, AEP performed an impairment analysis at the unit level on the remaining merchant generation assets in accordance with accounting guidance for impairments of long-lived assets. The evaluation was performed using generating unit specific estimated future cash flows and resulted in a material impairment of certain merchant generation fleet assets. As a result, AEP recorded a pretax impairment of $2.3 billion ($1.5 billion, net of tax) in Asset Impairments and Other Related Charges on the statements of income related to 2,684 MWs of Ohio merchant generation including Cardinal, Unit 1, 43.5% ownership interest in Conesville, Unit 4, Conesville, Units 5 and 6, 26.0% ownership interest in Stuart, Units 1-4, and 25.4% ownership interest in Zimmer, Unit 1, as well as Putnam coal and I&M’s Price River coal reserves, Desert Sky and Trent Wind Farms and the merchant generation portion of the Oklaunion Plant. As of December 31, 2016, the remaining net book value of these assets is $57 million. See “Merchant Generating Assets (Generation & Marketing Segment)” section of Note 7 for additional information.

Management continues to evaluate potential alternatives for the remaining merchant generation assets. These potential alternatives may include, but are not limited to, transfer or sale of AEP’s ownership interests, or a wind down of merchant coal-fired generation fleet operations. In February 2017, AEP signed an agreement to purchase Dynegy Corporation’s 40% ownership share of Conesville Plant, Unit 4.  Simultaneously, AEP signed an agreement to sell its 25.4% ownership share of Zimmer Plant, Unit 1 to Dynegy Corporation.  The transactions are expected to close in the second quarter of 2017, subject to FERC approval and are not expected to have a material impact on net income, cash flows and financial condition.  AEP is also continuing a separate strategic review and evaluating alternatives related to the 48 MW Racine Hydroelectric Plant. Management has not set a specific time frame for a decision on these assets. These alternatives could result in additional losses which could reduce future net income and cash flows and impact financial condition.

Renewable Generation Portfolio

The growth of AEP’s renewable generation portfolio reflects the company’s strategy to diversify generation resources to provide clean energy options to customers that meet both their energy and capacity needs. 

AEP has formed two new subsidiaries within the Generation & Marketing segment to further develop its renewable portfolio.  AEP OnSite Partners, LLC works directly with wholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies.  AEP OnSite Partners, LLC pursues projects where a suitable termed agreement is entered into with a credit-worthy counterparty.  AEP Renewables, LLC develops and/or acquires large

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scale renewable generation projects that are backed with long-term contracts with credit-worthy counterparties. These subsidiaries have approximately 41 MWs of renewable generation projects in operation and 83 MWs of renewable generation projects under construction with an estimated financial commitment of approximately $226 million. As of December 31, 2016, $171 million of costs have been incurred related to these projects.

Merchant Portion of Turk Plant

SWEPCo constructed the Turk Plant, a base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012 and is included in the Vertically Integrated Utilities segment. SWEPCo owns 73% (440 MWs) 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. As of December 31, 2016, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP. 

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.

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 would review base rates in 2014 and 2015 and that SWEPCo would 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. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for June 2017. 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.

2016 Texas Base Rate Case

In December 2016, SWEPCo filed a base rate request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management.

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


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Welsh Plant - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of approximately $850 million, excluding AFUDC. As of December 31, 2016, SWEPCo had incurred costs of $397 million, including AFUDC, and had remaining contractual construction obligations of $11 million related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. In March 2016, SWEPCo filed a request with the APSC to recover $69 million in environmental costs related to the Arkansas retail jurisdictional share of Welsh Plant, Units 1 and 3, which was approved by the APSC in August 2016. SWEPCo began recovering the Arkansas jurisdictional share of these costs in March 2016, subject to review in the next filed base rate proceeding. In September 2016, SWEPCo filed an additional request to increase the Arkansas retail jurisdictional share of the environmental investment by $10 million, for a total of $79 million. SWEPCo implemented the increase in September 2016. In December 2016, the LPSC approved deferral of certain expenses related to environmental controls installed at Welsh Plant, until these investments are put into base rates. The eligible Welsh Plant deferrals through December 31, 2016 are $8 million, excluding $5 million of unrecognized equity, subject to review by the LPSC, and include a WACC return on environmental investments and the related depreciation expense and taxes. SWEPCo will seek recovery of its project costs from customers 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 December 31, 2016, the net book value of Welsh Plant, Units 1 and 3 was $633 million, before cost of removal, including materials and supplies inventory and CWIP.  In April 2016, Welsh Plant, Unit 2 was retired. Upon retirement, $76 million was reclassified as Regulatory Assets on the balance sheets related to the net book value of Welsh Plant, Unit 2 and the related asset retirement obligation costs. In SWEPCo’s 2016 Texas Base Rate Case, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33%) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. Management will seek recovery of the remaining Welsh Plant, Unit 2 retirement-related regulatory assets in future rate proceedings.

If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. See the “Welsh Plant - Environmental Impact” section of Note 4.

2015 Oklahoma Base Rate Case

In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million. In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million, will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4, which would be recovered through the FAC.

In November 2016 and December 2016, the OCC issued orders that approved a net annual revenue increase of $19 million based upon a 9.5% return on common equity. The orders also included (a) approval to defer incurred costs related to PSO’s environmental compliance plan until those costs are included in base rates, (b) no determination related to the return of and return on the post-retirement remaining net book value of Northeastern Plant, Unit 4 since the April 2016 retirement was outside of the test year, (c) approval to include environmental consumable costs in the FAC (d) the continued depreciation of Northeastern Plant, Units 3 and 4 through 2040 (no accelerated depreciation) and (e) altered the system reliability rider by eliminating the expense portion of the rider and setting the capital portion of the rider at the December 2016 plant balance and approved recovery of deferred expenses and return on the capital balance incurred prior to the effective date of new tariffs in January 2017. Additionally, the orders stated that the cost recovery of new PPAs related to replacement power resulting from the retirement of Northeastern Plant, Unit 4 will be addressed in a future FAC proceeding. Effective December 2016, interim rates were terminated and the refund of over collections began and will be completed no later than October 2017. In accordance with the final order, updated rates and tariffs went into effect in January 2017.


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If any of these costs, including a return on Northeastern Plant, Unit 4, are ultimately 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.

Indiana Amended PJM Settlement Agreement

In November 2016, the IURC issued an order that approved an amended settlement agreement between I&M and certain intervenors.  This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017.

The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018.  Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018.

Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR)

In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NOx from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo.  The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC is scheduled for March 2017.

TCC and TNC Merger

Effective December 31, 2016, TCC and TNC merged into AEP Utilities, Inc., as approved by the FERC and the PUCT in September 2016 and December 2016, respectively. Upon merger, AEP Utilities, Inc. changed its name to AEP Texas Inc., but maintained TCC’s and TNC’s respective customer rates. The PUCT ordered certain post-merger conditions which included a) the sharing of certain interest rate savings with customers and b) an annual credit to customers of approximately $630 thousand for savings resulting from an expected reduction in post-merger debt issuance costs, effective until the next base rate case.

FERC Transmission Complaint and Proposed Modifications to Transmission Rates

In October 2016, several parties filed a joint complaint with the FERC claiming that the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. In November 2016, AEP affiliates filed an application with the FERC to modify the FERC formula transmission rate calculation, including adjustments for certain tax issues and a shift from historical to estimated expenses with a proposed effective date of January 1, 2017. The rates will be implemented based upon the date provided in the pending FERC order, subject to refund. Management

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believes its financial statements adequately address the impact of the complaint and the proposed modifications to AEP’s transmission rates in PJM. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

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. Management believes APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA.

In February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning in 2016. In July 2016, the Virginia SCC issued an order that denied the petition. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition.

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.

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

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

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


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In August 2015, PJM held its first base residual auction implementing CP rules for the June 2018 through May 2019 period. AGR cleared 7,209 MWs at the CP auction price of $164.77/MW-day. The base residual auction for the June 2019 through May 2020 period was conducted in May 2016. AGR cleared 7,301 MWs at the CP auction price of $100/MW-day. Shown below are the results for the June 2018 through May 2019 and June 2019 through May 2020 periods:
 
 
Capacity Performance
 
Base Capacity
PJM Auction Period
 
Auction Price
 
Auction Price
 
 
(dollars per MW day)
 
(dollars per MW day)
June 2018 through May 2019
 
164.77
 
150.00
June 2019 through May 2020
 
100.00
 
80.00

After the sale of the Darby, Gavin, Lawrenceburg and Waterford Plants in January 2017, AGR is no longer responsible for and does not receive capacity revenue for the portion of the cleared capacity associated with these plants.

The FERC order exempted Fixed Resource Requirement (FRR) entities, including APCo, I&M, KPCo and WPCo, from the CP rules through the delivery period ending May 2019. Beginning in June 2019, FRR entities are subject to CP rules.

LITIGATION

In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated.  For details on the regulatory proceedings and pending litigation see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.  The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.  In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiff’s claims. Several claims remained, 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. The plaintiff subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiff’s motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, Plaintiffs filed a notice of appeal on whether AEGCo and I&M are in breach of certain contract provisions that Plaintiffs allege operate to protect the Plaintiffs’ residual interests in

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the unit and whether the trial court erred in dismissing Plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. This matter is currently pending before the U.S. Court of Appeals for the Sixth Circuit. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

ENVIRONMENTAL ISSUES

AEP is implementing a substantial capital investment program and incurring additional operational costs to comply with environmental control requirements.  Additional investments and operational changes will need to be made in response to existing and anticipated requirements such as the CAA requirements to reduce emissions of SO2, NOx, PM, CO2 and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, rules governing the beneficial use and disposal of coal combustion products, clean water rules and renewal permits for certain water discharges.

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

AEP 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 AEP is 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.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of December 31, 2016, the AEP System had a total generating capacity of approximately 31,000 MWs, of which approximately 16,000 MWs are coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the fossil generating facilities. Based upon management estimates, AEP’s investment to meet these existing and proposed requirements ranges from approximately $4.3 billion to $4.9 billion through 2025.

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 the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.  In addition, management is continuing to evaluate the economic feasibility of environmental investments on both regulated and competitive plants.


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In May 2015, AEP retired the following plants or units of plants:
Company
 
Plant Name and Unit
 
Generating
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 December 31, 2016, the net book value of the AGR units listed above was zero.  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 approved for recovery, except for $148 million which management plans to seek regulatory approval.

In April 2016, AEP retired the following units of plants:
Company
 
Plant Name and Unit
 
Generating Capacity
 
 
 
 
(in MWs)
PSO
 
Northeastern Station, Unit 4
 
470

SWEPCo
 
Welsh Plant, Unit 2
 
528

Total
 
 
 
998


As of December 31, 2016, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of the PSO and SWEPCo units listed above was $161 million. For Northeastern Station, Unit 4, in November and December 2016, the OCC issued orders that provided no determination related to the return of and return on the post-retirement remaining net book value. These regulatory assets are pending regulatory approval. SWEPCo requested recovery of the Texas jurisdictional share (approximately 33%) of the net book value of Welsh Plant, Unit 2 in the 2016 Texas Base Rate Case. Management will seek recovery of the remaining PSO and SWEPCo regulatory assets in future rate proceedings.

In October 2015, KPCo obtained permits following the KPSC’s approval to convert its 278 MW Big Sandy Plant, Unit 1 to natural gas. Big Sandy Plant, Unit 1 began operations as a natural gas unit in May 2016.

APCo obtained permits following the Virginia SCC’s and WVPSC’s approval to convert its 470 MW Clinch River Plant, Units 1 and 2 to natural gas. In the third and fourth quarters of 2015, APCo retired the coal-related assets of Clinch River Plant, Units 1 and 2. Of the retired coal related assets for Clinch River Plant, Units 1 and 2, management plans to seek regulatory approval for $24 million. Clinch River Plant, Unit 1 and Unit 2 began operations as natural gas units in February 2016 and April 2016, respectively.

In January 2017, Dayton Power and Light Co. announced the future retirement of the 2,308 MW Stuart Plant, Units 1-4. The retirement is scheduled for June 2018. Stuart Plant, Units 1-4 are operated by Dayton Power and Light Co. and are jointly owned by AGR and nonaffiliated entities. AGR owns 600 MWs of the Stuart Plant, Units 1-4. As of December 31, 2016, AGR’s net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of the Stuart Plant, Units 1-4 was $221 thousand.

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. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit remanded the rule to the Federal EPA. In September 2016, the Federal EPA finalized its response to the remand for ozone season NOx budgets. In November 2016, the Federal EPA proposed to remove Texas from the annual SO2 and NOx budget programs. Texas would remain part of CSAPR’s ozone season NOx budget program. All of the states in which AEP’s power plants are located are covered by CSAPR. See “Cross-State Air Pollution Rule” section below.

The Federal EPA issued the final maximum achievable control technology (MACT) standards for coal and oil-fired power plants in 2012, but the rule was remanded to the Federal EPA upon further review. The Federal EPA issued a supplemental finding, received comments and affirmed its decision on the MACT standards for power plants. That decision has been challenged in the courts but the rule remains in effect. 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.  In January 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs, including a provision that postpones the due date for the next comprehensive SIP revisions until 2021.

The Federal EPA proposed disapproval of regional haze SIPs in a few states, including Arkansas and Texas.  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 were consistent with the environmental controls currently under construction. In September 2016, the Federal EPA published a final FIP that retains its BART determinations, but accelerates the schedule for implementation of certain required controls. The final rule is being challenged in the courts. In January 2016, the Federal EPA disapproved portions of the Texas regional haze SIP and promulgated a final FIP that did not include any BART determinations. That rule was challenged and stayed by the U.S. Court of Appeals for the Fifth Circuit Court. The parties engaged in settlement discussion but were unable to reach agreement. In January 2017, Federal EPA proposed source-specific BART requirements for SO2 from sources in Texas, including certain AEP units. The comment period has not yet closed.

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. Management supports compliance with CSAPR programs as satisfaction of the BART requirements.

The Federal EPA issued rules for CO2 emissions that apply to new and existing electric utility units. See “Climate Change, CO2 Regulation and Energy Policy” section below.

12


The Federal EPA also issued new, more stringent national ambient air quality standards (NAAQS) for PM in 2012, SO2 in 2010 and ozone in 2015. States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for facilities as a result of those evaluations. Management cannot currently predict the nature, stringency or timing of those requirements.

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

Cross-State Air Pollution Rule

In 2011, the Federal EPA issued CSAPR as a replacement of CAIR.  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.  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, although the Federal EPA has proposed to withdraw the annual CSAPR budget programs in Texas.  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. A petition for review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013. In April 2014, the U.S. Supreme Court issued a decision reversing in part the decision of the U.S. Court of Appeals for the District of Columbia Circuit and remanding the case for further proceedings consistent with the opinion. The Federal EPA filed a motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. The court granted the Federal EPA’s motion. The parties filed briefs and presented oral arguments. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit found that the Federal EPA over-controlled the SO2 and/or NOx budgets of 14 states. The U.S. Court of Appeals for the District of Columbia Circuit remanded the rule to the Federal EPA to timely revise the rule consistent with the court’s opinion while CSAPR remains in place.

In December 2015, the Federal EPA issued a proposal to revise the ozone season NOx budgets in 23 states beginning in 2017 to address transport issues associated with the 2008 ozone standard and the budget errors identified in the U.S. Court of Appeals for the District of Columbia Circuit’s July 2015 decision. The proposal was open for public comment through February 1, 2016. In October 2016, a final rule was issued that significantly reduces ozone season budgets in many states and discounts the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. The rule has been challenged in the courts and petitions for administrative reconsideration have been filed. Management believes that there are flaws in the underlying analysis of and justification for this rule. Management is evaluating compliance options for the 2017 ozone season, including any opportunity to further optimize NOx emissions and availability of allowances.


13


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. Management obtained a one-year administrative extension at several units to facilitate the installation of controls or to avoid a serious reliability problem.

In April 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the April 2012 final rule. Industry trade groups and several states filed petitions for further review in the U.S. Supreme Court and the court granted those petitions in November 2014.

In June 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit remanded the Mercury and Air Toxics Standards (MATS) rule for further proceedings consistent with the U.S. Supreme Court’s 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 Federal EPA issued notice of a supplemental finding concluding that it is appropriate and necessary to regulate HAP emissions from coal-fired and oil-fired units. Management submitted comments on the proposal. In April 2016, the Federal EPA affirmed its determination that regulation of HAPs from electric generating units is necessary and appropriate. Petitions for review of the Federal EPA’s April 2016 determination have been filed in the U.S. Court of Appeals for the District of Columbia Circuit. The rule remains in effect.

Climate Change, CO2 Regulation and Energy Policy

The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions.  Management is taking steps to comply with these requirements, including increasing wind and solar installations and power purchases and broadening the AEP System’s portfolio of energy efficiency programs.

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

The final emissions guidelines for existing sources, known as the Clean Power Plan (CPP), are based on a series of declining emission rates that are implemented beginning in 2022 through 2029. The final emission rate is 771 pounds of CO2 per MWh for existing natural gas combined cycle units and 1,305 pounds of CO2 per MWh for existing fossil steam units in 2030 and thereafter. The Federal EPA also developed a set of rate-based and mass-based state goals.

The Federal EPA also published proposed “model” rules that can be adopted by the states that would allow sources within “trading ready” state programs to trade, bank or sell allowances or credits issued by the states. These rules would also be the basis for any federal plan issued by the Federal EPA in a state that fails to submit or receive approval for a state plan. The Federal EPA intends to finalize either a rate-based or mass-based trading program that can be enforced in states that fail to submit approved plans by the deadlines established in the final guidelines. The Federal EPA established a 90-day public comment period on the proposed rules and management submitted comments. In June 2016, the Federal EPA issued a separate proposal for the Clean Energy Incentive Program (CEIP) that was included in the model rules. Through the CEIP, states could issue allowances or credits for eligible actions prior to the first

14


compliance period under the CPP. The final rules are being challenged in the courts. In February 2016, the U.S. Supreme Court issued a stay on the final Clean Power Plan, including all of the deadlines for submission of initial or final state plans. The stay will remain in effect until a final decision is issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review.

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 AEP to close some coal-fired facilities and could lead to possible impairment of assets.

Coal Combustion Residual Rule

In April 2015, the Federal EPA published a final 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 final rule became effective in October 2015. The Federal EPA regulates CCR as a non-hazardous solid waste by its issuance of new minimum federal solid waste management standards. 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, 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. The CCR rule requirements contain a compliance schedule spanning an approximate four year implementation period. If CCR units do not meet these standards within the timeframes provided, they will be required to close. Extensions of time for closure are available provided there is no alternative disposal capacity or the owner can certify cessation of a boiler by a certain date. Challenges to the rule by industry associations of which AEP is a member are proceeding. In April 2016, the parties entered into a settlement agreement that would require the Federal EPA to reconsider certain aspects of the rule. In June 2016, the U.S. Court of Appeals for the District of Columbia issued an order granting the voluntary remand of certain provisions including the Federal EPA’s issuance of a rule vacating the provision creating specific closure requirements for inactive surface impoundments that complete closure by April 17, 2018. In August 2016, the Federal EPA proposed a direct final rule to extend the deadlines for these facilities to comply with the CCR standards. The proposed rule received no adverse comments and became effective 60 days following publication. Management does not believe the direct final rule will have a significant impact on its planned pond closures. The Federal EPA will also use its best efforts to complete reconsideration of all of the affected provisions within three years.

In December 2016, the U.S. Congress passed legislation authorizing states to submit programs to regulate CCR facilities, and the Federal EPA to approve such programs if they are no less stringent than the minimum federal standards. The Federal EPA may also enforce compliance with the minimum standards until a state program is approved or if states fail to adopt their own programs.

Because AEP currently uses surface impoundments and landfills to manage CCR materials at generating facilities, significant costs will be incurred to upgrade or close and replace these existing facilities at some point in the future as the new rule is implemented. Management recorded a $95 million increase in asset retirement obligations in the second quarter of 2015 primarily due to the publication of the final rule. Management will continue to evaluate the rule’s impact on operations.

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 AEP’s generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses.  Encapsulated beneficial uses are not materially impacted by the new rule but additional demonstrations may be required to continue land applications in significant amounts except in road construction projects.

15


Clean Water Act (CWA) Regulations

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

In addition, the Federal EPA developed revised effluent limitation guidelines for electricity generating facilities.  A final rule was issued in November 2015. The rule has been challenged in the U.S. Court of Appeals for the Fifth Circuit. In addition to other requirements, the final rule establishes limits on flue gas desulfurization wastewater, zero discharge for fly ash and bottom ash transport water and flue gas mercury control wastewater. The applicability of these requirements is as soon as possible after November 2018 and no later than December 2023. These new requirements will be implemented through each facility’s wastewater discharge permit. Management continues to assess technology additions and retrofits.

In June 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This jurisdictional definition applies to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are: permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. The final definition continues to recognize traditional navigable waters of the U.S. as jurisdictional as well as certain exclusions. The rule also contains a number of new specific definitions and criteria for determining whether certain other waters are jurisdictional because of a “significant nexus.” Management believes that clarity and efficiency in the permitting process is needed. Management remains concerned that the rule introduces new concepts and could subject more of AEP’s operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. The final rule is being challenged in both courts of appeal and district courts. Challengers include industry associations of which AEP is a member. The U.S. Court of Appeals for the Sixth Circuit granted a nationwide stay of the rule pending jurisdictional determinations. In February 2016, the U.S. Court of Appeals for the Sixth Circuit issued a decision holding that it has exclusive jurisdiction to decide the challenges to the “waters of the United States” rule. Industry, state and related associations have filed petitions for a rehearing of the jurisdictional decision. In April 2016, the U.S. Court of Appeals for the Sixth Circuit denied the petitions. In January 2017, the decision was appealed to the U.S. Supreme Court, which granted certiorari to review the jurisdictional issue.


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RESULTS OF OPERATIONS

SEGMENTS

AEP’s primary business is the generation, transmission and distribution of electricity.  Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its 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.

AEP’s 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 and AEP Texas.
OPCo purchases energy and capacity at auction to serve SSO customers and provides transmission and distribution services for all connected load.
With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other.

AEP Transmission Holdco

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

Generation & Marketing

Competitive generation in ERCOT and PJM.
Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO.
Contracted renewable energy investments and management services.

The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.

The following discussion of AEP’s results of operations by operating segment includes an analysis of gross margin, which is a non-GAAP financial measure. Gross margin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation as well as Purchased Electricity for Resale, Generation Deferrals and Amortization of Generation Deferrals as presented in the Registrants statements of income as applicable. These expenses are generally collected from customers through cost recovery mechanisms. As such, management uses gross margin for internal reporting analysis as it excludes the fluctuations in revenue caused by changes in these expenses. Operating income, which is presented in accordance with GAAP in AEP’s statements of income, is the most directly comparable GAAP financial measure to the presentation of gross margin. AEP’s definition of gross margin may not be directly comparable to similarly titled financial measures used by other companies.


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The table below presents Earnings (Loss) Attributable to AEP Common Shareholders by segment for the years ended December 31, 2016, 2015 and 2014.
 
 
Years Ended December 31,
 
 
2016
 
2015
 
2014
 
 
(in millions)
Vertically Integrated Utilities
 
$
979.9

 
$
896.5

 
$
707.6

Transmission and Distribution Utilities
 
482.1

 
352.4

 
352.2

AEP Transmission Holdco
 
266.3

 
191.2

 
150.8

Generation & Marketing
 
(1,198.0
)
 
366.0

 
367.4

Corporate and Other
 
80.6

 
241.0

 
55.8

Earnings Attributable to AEP Common Shareholders
 
$
610.9

 
$
2,047.1

 
$
1,633.8


AEP CONSOLIDATED

2016 Compared to 2015

Earnings Attributable to AEP Common Shareholders decreased from $2 billion in 2015 to $611 million in 2016 primarily due to:

An impairment of certain merchant generation assets.
A decrease in generation revenues due to lower capacity revenue and a decrease in wholesale energy prices.

These decreases were partially offset by:

A decrease in system income taxes primarily due to reduced pretax book income as a result of the impairment of certain merchant generation assets as well as the reversal of valuation allowances related to the pending sale of certain merchant generation assets and the settlement of a 2011 audit issue with the IRS, as well as favorable 2015 income tax return adjustments related to AEP’s commercial barging operations.
Favorable rate proceedings during 2016 in AEP’s various jurisdictions.

2015 Compared to 2014

Earnings Attributable to AEP Common Shareholders increased from $1.6 billion in 2014 to $2 billion in 2015 primarily due to:

Favorable rate proceedings during 2015 in AEP’s various jurisdictions.
The gain on the sale of commercial barge operations.
An increase in transmission investment which resulted in higher revenues and income.
A decrease in expenses due to a settlement and revision of certain asset retirement obligations.
Favorable retail, trading and marketing activity.

These increases were partially offset by:

A decrease in generation revenues due to lower capacity revenue.
A decrease in off-system sales margins due to lower market prices and reduced sales volumes.
An increase in depreciation and amortization expenses primarily due to higher depreciable base.

AEP’s results of operations by operating segment are discussed below.

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VERTICALLY INTEGRATED UTILITIES
 
 
Years Ended December 31,
Vertically Integrated Utilities
 
2016
 
2015
 
2014
 
 
(in millions)
Revenues
 
$
9,091.9

 
$
9,172.2

 
$
9,484.4

Fuel and Purchased Electricity
 
3,079.3

 
3,413.6

 
3,953.4

Gross Margin
 
6,012.6

 
5,758.6

 
5,531.0

Other Operation and Maintenance
 
2,702.9

 
2,529.5

 
2,515.0

Asset Impairments and Other Related Charges
 
10.5

 

 

Depreciation and Amortization
 
1,073.8

 
1,062.6

 
1,033.0

Taxes Other Than Income Taxes
 
390.8

 
383.1

 
370.8

Operating Income
 
1,834.6

 
1,783.4

 
1,612.2

Interest and Investment Income
 
4.8

 
4.6

 
3.4

Carrying Costs Income
 
10.5

 
11.8

 
6.7

Allowance for Equity Funds Used During Construction
 
45.5

 
63.2

 
46.3

Interest Expense
 
(522.1
)
 
(517.4
)
 
(525.5
)
Income Before Income Tax Expense and Equity Earnings
 
1,373.3

 
1,345.6

 
1,143.1

Income Tax Expense
 
397.3

 
449.3

 
433.5

Equity Earnings of Unconsolidated Subsidiaries
 
8.0

 
3.9

 
2.2

Net Income
 
984.0

 
900.2

 
711.8

Net Income Attributable to Noncontrolling Interests
 
4.1

 
3.7

 
4.2

Earnings Attributable to AEP Common Shareholders
 
$
979.9

 
$
896.5

 
$
707.6

Summary of KWh Energy Sales for Vertically Integrated Utilities
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2016
 
2015
 
2014
 
 
 
(in millions of KWhs)
 
Retail:
 
 
 
 
 
 
 
Residential
 
32,606

 
32,720

 
34,073

 
Commercial
 
25,229

 
25,006

 
25,048

 
Industrial
 
34,029

 
34,638

 
35,281

 
Miscellaneous
 
2,316

 
2,279

 
2,311

 
Total Retail
 
94,180

 
94,643

 
96,713

 
 
 
 
 
 
 
 
 
Wholesale (a)
 
23,081

 
25,353

 
34,241

 
 
 
 
 
 
 
 
 
Total KWhs
 
117,261

 
119,996

 
130,954

 

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



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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 the eastern region have a larger effect on revenues than changes in the 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
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
2016
 
2015
 
2014
 
 
(in degree days)
Eastern Region
 
 
 
 
 
 
Actual – Heating (a)
 
2,541

 
2,710

 
3,313

Normal – Heating (b)
 
2,767

 
2,755

 
2,740

 
 
 
 
 
 
 
Actual – Cooling (c)
 
1,345

 
1,113

 
932

Normal – Cooling (b)
 
1,075

 
1,075

 
1,080

 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
Actual – Heating (a)
 
1,130

 
1,379

 
1,840

Normal – Heating (b)
 
1,495

 
1,491

 
1,510

 
 
 
 
 
 
 
Actual – Cooling (c)
 
2,480

 
2,315

 
2,049

Normal – Cooling (b)
 
2,215

 
2,210

 
2,203


(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)
Cooling degree days are calculated on a 65 degree temperature base.

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2016 Compared to 2015

Reconciliation of Year Ended December 31, 2015 to Year Ended December 31, 2016
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Year Ended December 31, 2015
 
$
896.5

 
 
 
Changes in Gross Margin:
 
 
Retail Margins
 
274.5

Off-system Sales
 
(18.7
)
Transmission Revenues
 
(6.1
)
Other Revenues
 
4.3

Total Change in Gross Margin
 
254.0

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(173.4
)
Asset Impairments and Other Related Charges
 
(10.5
)
Depreciation and Amortization
 
(11.2
)
Taxes Other Than Income Taxes
 
(7.7
)
Interest and Investment Income
 
0.2

Carrying Costs Income
 
(1.3
)
Allowance for Equity Funds Used During Construction
 
(17.7
)
Interest Expense
 
(4.7
)
Total Change in Expenses and Other
 
(226.3
)
 
 
 
Income Tax Expense
 
52.0

Equity Earnings
 
4.1

Net Income Attributable to Noncontrolling Interests
 
(0.4
)
 
 
 
Year Ended December 31, 2016
 
$
979.9


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 $275 million primarily due to the following:
The effect of rate proceedings in AEP’s service territories which include:
A $158 million increase in rates in West Virginia and Virginia, which includes recognition of deferred billing in West Virginia as approved by the WVPSC in June 2016. This increase is partially offset by a 2015 adjustment affected by the amended Virginia law that has an impact on biennial reviews.
A $48 million increase for KPCo primarily due to increases in base rates and riders.
A $41 million increase for I&M due to increases in riders in the Indiana service territory.
A $26 million increase for PSO due to base rate increases implemented in January 2016 and rider revenues.
A $23 million increase for SWEPCo due to revenue increases from rate riders in Arkansas and Texas.
For the increases described above, $177 million relate to riders/trackers which have corresponding increases in expense items below.
A $29 million increase in weather-related usage primarily in the eastern region.
These increases were partially offset by:
A $22 million decrease in weather-normalized margins primarily in the eastern region.
A $20 million decrease for SWEPCo in municipal and cooperative revenues due to a true-up of formula rates in 2015.
An $11 million decrease for I&M in FERC municipal and cooperative revenues due to annual formula rate adjustments offset by increased formula rate changes.
Margins from Off-system Sales decreased $19 million primarily due to lower market prices and decreased sales volumes.


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Transmission Revenues decreased $6 million primarily due to the following:
A $27 million decrease due to lower Network Integration Transmission Service (NITS) revenues.
This decrease was partially offset by:
An $14 million increase in SPP Non-Affiliated Base Plan Funding associated with increased transmission investments. This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.
$5 million of SPP sponsor-funded transmission upgrades recorded in 2016. This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.
Other Revenues increased $4 million primarily due to increased revenues from demand side management programs in Kentucky, partially offset within Other Operation and Maintenance below.

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

Other Operation and Maintenance expenses increased $173 million primarily due to the following:
A $103 million increase in recoverable expenses, primarily including PJM, vegetation management, energy efficiency and storm expenses fully recovered in rate recovery riders/trackers within Retail Margins above.
A $57 million increase associated with amortization of deferred transmission costs in accordance with the Virginia Transmission Rate Adjustment Clause effective January 2016. This increase in expense is offset within Retail Margins above.
A $35 million increase due to a charitable donation to the AEP Foundation.
A $33 million increase in SPP and PJM transmission services expense.
A $6 million increase due to the reduction of an environmental liability in 2015 at I&M.
These increases were partially offset by:
A $61 million decrease in plant outages, primarily planned outages in the eastern region.
A $6 million decrease due to a 2016 gain on the sale of property in the APCo region.
Asset Impairments and Other Related Charges increased $11 million due to the impairment of I&M’s Price River Coal reserves.
Depreciation and Amortization expenses increased $11 million primarily due to:
A $42 million increase due to a higher depreciable base.
These increases were partially offset by the following:
A $14 million decrease in the amortization of capitalized software due to retirements in 2015.
An $8 million decrease due to a revision in I&M’s nuclear asset retirement obligation (ARO) estimate, which has a corresponding increase in Other Operation and Maintenance expenses above.
A $4 million decrease in amortization related to the advanced metering infrastructure projects in Oklahoma.
A $3 million decrease in ARO expenses due to steam plant retirements in 2015.
Taxes Other Than Income Taxes increased $8 million primarily due to an increase in property taxes as a result of increased property investment.
Allowance for Equity Funds Used During Construction decreased $18 million primarily due to the completion of environmental projects at SWEPCo.
Interest Expense increased $5 million primarily due to the following:
An $11 million increase due to higher long-term debt balances at I&M.
This increase was partially offset by:
A $7 million decrease primarily due to the deferral of the debt component of carrying charges on environmental control costs for projects in Oklahoma at Northeastern Plant, Unit 3 and the Comanche Plant.
Income Tax Expense decreased $52 million primarily due to the recording of federal and state income tax adjustments and other book/tax differences which are accounted for on a flow-through basis, partially offset by an increase in pretax book income.
Equity Earnings increased $4 million primarily due to favorable tax adjustments in 2016.



22


2015 Compared to 2014

Reconciliation of Year Ended December 31, 2014 to Year Ended December 31, 2015
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Year Ended December 31, 2014
 
$
707.6

 
 
 
Changes in Gross Margin:
 
 
Retail Margins
 
377.6

Off-system Sales
 
(124.9
)
Transmission Revenues
 
(26.4
)
Other Revenues
 
1.3

Total Change in Gross Margin
 
227.6

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(14.5
)
Depreciation and Amortization
 
(29.6
)
Taxes Other Than Income Taxes
 
(12.3
)
Interest and Investment Income
 
1.2

Carrying Costs Income
 
5.1

Allowance for Equity Funds Used During Construction
 
16.9

Interest Expense
 
8.1

Total Change in Expenses and Other
 
(25.1
)
 
 
 
Income Tax Expense
 
(15.8
)
Equity Earnings
 
1.7

Net Income Attributable to Noncontrolling Interests
 
0.5

 
 
 
Year Ended December 31, 2015
 
$
896.5


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 $378 million primarily due to the following:
The effect of successful rate proceedings in AEP’s service territories which included:
A $158 million increase primarily due to increases in rates in West Virginia, as well as an adjustment due to the amended Virginia law impacting biennial reviews.
An $88 million increase for I&M primarily due to rate increases from Indiana rate riders and annual FERC formula rate adjustments.
A $79 million increase for SWEPCo due to revenue increases from rate riders in Louisiana and Texas and increases in municipal and cooperative revenues due to annual FERC formula rate adjustments.
A $25 million increase for PSO primarily due to revenue increases from rate riders.
For the increases described above, $70 million relate to riders/trackers which have corresponding increases in expense items below.
A $72 million decrease in Fuel and Purchased Electricity primarily due to the transfer of a one-half interest in the Mitchell Plant from AGR to WPCo in January 2015. This decrease was partially offset by increases in other expense items below.
A $32 million decrease in PJM charges not currently included in rate recovery riders/trackers.
These increases were partially offset by:
A $70 million decrease in weather-normalized load primarily due to lower residential and industrial sales.
A $32 million decrease in weather-related usage primarily in the eastern region.
Margins from Off-system Sales decreased $125 million primarily due to lower market prices and decreased sales volumes.
Transmission Revenues decreased $26 million primarily due to decreased PJM revenues, partially offset by an increase in SPP margins.

23


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

Other Operation and Maintenance expenses increased $15 million primarily due to the following:
A $56 million increase in recoverable expenses, primarily PJM expenses and vegetation management expenses currently fully recovered in rate recovery riders/trackers, partially offset by lower River Transportation Division (RTD) barging costs.
A $23 million increase in plant-related expenses primarily due to the transfer of a one-half interest in the Mitchell Plant from AGR to WPCo in January 2015.  This increase was offset by an increase in Retail Margins above.
A $10 million increase in SPP and PJM transmission services.
A $4 million increase in regulatory commission expenses.
These increases were partially offset by:
A $41 million decrease in employee-related expenses.
A $25 million decrease in vegetation management expenses not included in riders/trackers.
A $14 million decrease in environmental liabilities at I&M.
Depreciation and Amortization expenses increased $30 million primarily due to overall higher depreciable base as well as amortization related to an advanced metering rider implemented in November 2014 in Oklahoma.
Taxes Other Than Income Taxes increased $12 million primarily due to an increase in property taxes.
Allowance for Equity Funds Used During Construction increased $17 million primarily due to increases in environmental and transmission projects.
Interest Expense decreased $8 million primarily due to lower interest rates on APCo long-term debt.
Income Tax Expense increased $16 million primarily due to an increase in pretax book income, partially offset by the recording of state and federal income tax adjustments and other book/tax differences which are accounted for on a flow-through basis.

24


TRANSMISSION AND DISTRIBUTION UTILITIES
 
 
Years Ended December 31,
Transmission and Distribution Utilities
 
2016
 
2015
 
2014
 
 
(in millions)
Revenues
 
$
4,422.4

 
$
4,556.6

 
$
4,813.6

Purchased Electricity
 
837.1

 
1,144.2

 
1,676.5

Generation Deferrals
 
(82.7
)
 
(30.7
)
 
(157.0
)
Amortization of Generation Deferrals
 
242.9

 
169.1

 
110.9

Gross Margin
 
3,425.1

 
3,274.0

 
3,183.2

Other Operation and Maintenance
 
1,386.7

 
1,328.9

 
1,276.1

Depreciation and Amortization
 
649.9

 
686.4

 
657.8

Taxes Other Than Income Taxes
 
494.3

 
478.3

 
453.4

Operating Income
 
894.2

 
780.4

 
795.9

Interest and Investment Income
 
14.8

 
6.4

 
10.1

Carrying Costs Income
 
20.0

 
11.8

 
26.5

Allowance for Equity Funds Used During Construction
 
15.1

 
15.5

 
11.7

Interest Expense
 
(256.9
)
 
(276.2
)
 
(280.3
)
Income Before Income Tax Expense
 
687.2

 
537.9

 
563.9

Income Tax Expense
 
205.1

 
185.5

 
211.7

Net Income
 
482.1

 
352.4

 
352.2

Net Income Attributable to Noncontrolling Interests
 

 

 

Earnings Attributable to AEP Common Shareholders
 
$
482.1

 
$
352.4

 
$
352.2

Summary of KWh Energy Sales for Transmission and Distribution Utilities
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2016
 
2015
 
2014
 
 
 
(in millions of KWhs)
 
Retail:
 
 
 
 
 
 
 
Residential
 
26,191

 
25,735

 
26,209

 
Commercial
 
25,922

 
25,268

 
25,307

 
Industrial
 
22,179

 
22,353

 
21,830

 
Miscellaneous
 
700

 
702

 
713

 
Total Retail (a)
 
74,992

 
74,058

 
74,059

 
 
 
 
 
 
 
 
 
Wholesale (b)
 
1,888

 
1,701

 
2,198

 
 
 
 
 
 
 
 
 
Total KWhs
 
76,880

 
75,759

 
76,257

 

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



25


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 the eastern region have a larger effect on revenues than changes in the 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
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
2016
 
2015
 
2014
 
 
(in degree days)
Eastern Region
 
 
 
 
 
 
Actual – Heating (a)
 
2,957

 
3,235

 
3,734

Normal – Heating (b)
 
3,245

 
3,226

 
3,230

 
 
 
 
 
 
 
Actual – Cooling (c)
 
1,248

 
975

 
949

Normal – Cooling (b)
 
969

 
970

 
960

 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
Actual – Heating (a)
 
201

 
390

 
428

Normal – Heating (b)
 
328

 
325

 
337

 
 
 
 
 
 
 
Actual – Cooling (d)
 
3,058

 
2,718

 
2,553

Normal – Cooling (b)
 
2,648

 
2,642

 
2,618


(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.

26


2016 Compared to 2015
 
Reconciliation of Year Ended December 31, 2015 to Year Ended December 31, 2016
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
Year Ended December 31, 2015
 
$
352.4

 
 
 
Changes in Gross Margin:
 
 
Retail Margins
 
185.4

Off-System Sales
 
46.3

Transmission Revenues
 
(0.6
)
Other Revenues
 
(80.0
)
Total Change in Gross Margin
 
151.1

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(57.8
)
Depreciation and Amortization
 
36.5

Taxes Other Than Income Taxes
 
(16.0
)
Interest and Investment Income
 
8.4

Carrying Costs Income
 
8.2

Allowance for Equity Funds Used During Construction
 
(0.4
)
Interest Expense
 
19.3

Total Change in Expenses and Other
 
(1.8
)
 
 
 
Income Tax Expense
 
(19.6
)
 
 
 
Year Ended December 31, 2016
 
$
482.1


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 $185 million primarily due to the following:
A $117 million increase in Ohio transmission and PJM revenues primarily due to the energy supplied as a result of the Ohio auction and a regulatory change which resulted in revenues collected through a non-bypassable transmission rider, partially offset by a corresponding decrease in Transmission Revenues below.
An $83 million increase due to the impact of a 2016 regulatory deferral of capacity costs related to OPCo's December 2016 Global Settlement.
A $44 million increase in Ohio riders such as Universal Service Fund (USF) and gridSMART®. This increase in Retail Margins was primarily offset by an increase in Other Operation and Maintenance expenses below.
A $34 million increase in collections of PIRR carrying charges in Ohio as a result of the June 2016 PUCO order.
A $24 million increase in revenues associated with the Ohio Distribution Investment Rider (DIR). This increase was partially offset in various line items below.
A $22 million increase in AEP Texas weather-normalized margins primarily in the residential class.
A $20 million increase in AEP Texas revenues primarily due to the recovery of ERCOT transmission expenses, offset in Other Operation and Maintenance expenses below.
A $17 million increase in AEP Texas revenues primarily due to the recovery of distribution expenses.
These increases were partially offset by:
A $150 million net decrease due to the impact of 2016 provisions for refund primarily related to OPCo's December 2016 Global Settlement.
A $16 million decrease in revenues associated with the recovery of 2012 storm costs under the Ohio Storm Damage Recovery Rider which ended in April 2015. This decrease in Retail Margins was primarily offset by a decrease in Other Operation and Maintenance expenses below.

27


Margins from Off-system Sales increased $46 million primarily due to the following:
A $41 million increase due to a reversal of a 2015 provision for regulatory loss in Ohio.
An $8 million increase primarily due to prior year losses in Ohio from a power contract with OVEC.
These increases were partially offset by:
A $3 million decrease in margins from a power contract with AEPEP for Oklaunion.
Transmission Revenues decreased $1 million primarily due to the following:
A $56 million decrease in NITS revenue primarily due to OPCo assuming the responsibility for items determined to be cost-based transmission-related charges that were the responsibility of the CRES providers prior to June 2015, partially offset by a corresponding increase in Retail Margins above.
This decrease was partially offset by:
A $36 million increase primarily due to increased transmission investment in ERCOT.
A $19 million increase in Ohio due to a FERC settlement recorded in 2015 and FERC formula rate true-up adjustments.
Other Revenues decreased $80 million primarily due to a decrease in Texas securitization revenue as a result of the final maturity of the first Texas securitization bond, offset in Depreciation and Amortization and other expense items below.


28


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

Other Operation and Maintenance expenses increased $58 million primarily due to the following:
A $73 million increase in recoverable expenses, primarily including PJM expenses and gridSMART® expenses, currently fully recovered in rate recovery riders/trackers within Retail Margins above.
A $28 million increase due to charitable donations, including the AEP Foundation.
A $21 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins above.
These increases were partially offset by:
A $14 million decrease due to the completion of the Ohio amortization of 2012 deferred storm expenses in April 2015. This decrease was offset by a corresponding decrease in Retail Margins above.
A $13 million decrease in distribution expenses primarily related to storms and 2015 asset inspections.
A $12 million decrease in vegetation management expenses.
A $12 million decrease related to a 2015 regulatory settlement in Ohio.
A $6 million decrease due to a PUCO ordered contribution to the Ohio Growth Fund recorded in 2015.
Depreciation and Amortization expenses decreased $37 million primarily due to the following:
A $65 million decrease in the Texas securitization transition assets due to the final maturity of the first Texas securitization bond, which is offset in Other Revenues above.
A $7 million decrease in the amortization of capitalized software due to 2015 retirements.
A $4 million decrease in recoverable gridSMART® depreciation expenses in Ohio. This decrease was partially offset by a corresponding decrease in Retail Margins above.
These decreases were partially offset by:
A $20 million increase in recoverable Ohio DIR depreciation expense. This increase was offset by a corresponding increase in Retail Margins above.
A $20 million increase in depreciation expense primarily due to an increase in depreciable base of transmission and distribution assets.
Taxes Other Than Income Taxes increased $16 million primarily due to increased property taxes in Ohio resulting from additional investments in transmission and distribution assets and higher tax rates.
Interest and Investment Income increased $8 million primarily due to a settlement with the IRS related to the U.K. Windfall Tax.
Carrying Costs Income increased $8 million primarily due to the following:
A $14 million increase due to the impact of a 2016 regulatory deferral of carrying costs related to OPCo's December 2016 Global Settlement.
A $4 million increase primarily due to a 2015 unfavorable adjustment related to gridSMART® capital carrying charges in Ohio.
These increases were partially offset by:
A $10 million decrease due to the collection of carrying costs on Ohio deferred capacity charges beginning June 2015.
Interest Expense decreased $19 million primarily due to:
A $14 million decrease in the Texas securitization transition assets due to the final maturity of the first Texas securitization bond. This decrease was offset by a corresponding decrease in Other Revenues above.
A $12 million decrease due to the maturity of an OPCo senior unsecured note in June 2016.
A $2 million decrease in recoverable DIR interest expenses in Ohio. This decrease was offset by a corresponding decrease in Retail Margins above.
These decreases were partially offset by the following:
An $11 million increase due to issuances of senior unsecured notes by AEP Texas.
Income Tax Expense increased $20 million primarily due to an increase in pretax book income partially offset by the recording of state and federal income tax adjustments and the settlement of a 2011 audit issue with the IRS.

29


2015 Compared to 2014
 
Reconciliation of Year Ended December 31, 2014 to Year Ended December 31, 2015
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
Year Ended December 31, 2014
 
$
352.2

 
 
 
Changes in Gross Margin:
 
 
Retail Margins
 
199.1

Off-System Sales
 
(28.5
)
Transmission Revenues
 
(83.7
)
Other Revenues
 
3.9

Total Change in Gross Margin
 
90.8

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(52.8
)
Depreciation and Amortization
 
(28.6
)
Taxes Other Than Income Taxes
 
(24.9
)
Interest and Investment Income
 
(3.7
)
Carrying Costs Income
 
(14.7
)
Allowance for Equity Funds Used During Construction
 
3.8

Interest Expense
 
4.1

Total Change in Expenses and Other
 
(116.8
)
 
 
 
Income Tax Expense
 
26.2

 
 
 
Year Ended December 31, 2015
 
$
352.4


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 $199 million primarily due to the following:
A $131 million increase in Ohio transmission and PJM revenues primarily due to energy supplied as a result of the Ohio auction and a regulatory change which resulted in revenues collected through a non-bypassable transmission rider, partially offset by a corresponding decrease in Transmission Revenues below.
A $50 million increase in Ohio rider revenues associated with the Distribution Investment Rider (DIR), the gridSMART® Rider, the Enhanced Service Reliability (ESR) Rider and the RSR. These increases in rider revenues are partially offset by net increases in other expense items below.
A $33 million negative Ohio regulatory provision recorded in 2014.
A $26 million increase in TCC and TNC revenues primarily due to the recovery of ERCOT transmission expenses, offset in Other Operation and Maintenance expenses below.
These increases were partially offset by:
A $25 million decrease in revenues associated with the recovery of 2012 storm costs under the Ohio Storm Damage Recovery Rider which ended in April 2015. This decrease in Retail Margins is offset by a decrease in Other Operation and Maintenance expenses below.
A $17 million decrease in Ohio Energy Efficiency/Peak Demand Reduction (EE/PDR) Rider revenues. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
An $11 million decrease in revenues associated with the Universal Service Fund (USF) surcharge. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
Margins from Off-system Sales decreased $29 million primarily due to losses from a legacy OPCo power contract.


30


Transmission Revenues decreased $84 million primarily due to the following:
An $80 million decrease in PJM Network Integrated Transmission Service (NITS) revenue primarily due to OPCo assuming the responsibility for items determined to be cost-based transmission-related charges that were the responsibility of the CRES providers prior to June 2015, partially offset by a corresponding increase in Retail Margins above.
A $12 million decrease in Ohio revenues related to a lower annual transmission formula rate true-up.
A $9 million OPCo transmission regulatory settlement in 2015.
These decreases were partially offset by:
A $25 million increase primarily due to increased transmission investment in ERCOT.

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

Other Operation and Maintenance expenses increased $53 million primarily due to the following:
A $72 million increase in recoverable PJM, ERCOT and gridSMART® expenses. These increases were offset by increases in Retail Margins above.
A $19 million increase in distribution expenses including system improvements and storm expenses.
A $12 million increase related to a regulatory settlement in Ohio.
A $6 million increase due to PUCO ordered contributions to the Ohio Growth Fund.
These increases were partially offset by:
A $26 million decrease due to the completion of the amortization of 2012 deferred storm expenses in April 2015. This decrease was offset by a corresponding decrease in Retail Margins above.
A $17 million decrease in EE/PDR costs and associated deferrals. This decrease was offset by a corresponding decrease in Retail Margins above.
An $11 million decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset by a corresponding decrease in Retail Margins above.
Depreciation and Amortization expenses increased $29 million primarily due to the following:
A $29 million increase due to an increase in the depreciable base of transmission and distribution assets.
An $8 million increase in amortization of TCC’s securitization transition asset, partially offset in Other Revenues.
An $8 million increase in amortization expenses for the collection of carrying costs on deferred capacity charges beginning June 2015. This increase was offset by a corresponding increase in Retail Margins above.
These increases were partially offset by:
A $9 million decrease in recoverable DIR depreciation expense. This decrease was offset by a decrease in Retail Margins above.
An $8 million decrease in recoverable gridSMART® depreciation expense. This decrease was offset by a decrease in Retail Margins above.
Taxes Other Than Income Taxes increased $25 million primarily due to increased property taxes.
Interest and Investment Income decreased $4 million primarily due to a decrease in affiliated notes payable for OPCo. This decrease was offset by a decrease in Interest Expense.
Carrying Costs Income decreased $15 million primarily due to the collection of carrying costs on deferred capacity charges beginning June 2015.
Income Tax Expense decreased $26 million primarily due to a decrease in pretax book income and by the recording of state income tax adjustments.

31


AEP TRANSMISSION HOLDCO


Years Ended December 31,
AEP Transmission Holdco

2016

2015

2014


(in millions)
Transmission Revenues

$
512.8


$
329.2


$
191.9

Other Operation and Maintenance

55.3


38.4


28.7

Depreciation and Amortization

67.1


43.0


23.7

Taxes Other Than Income Taxes

88.7


66.0


31.8

Operating Income

301.7


181.8


107.7

Interest and Investment Income
 
0.4

 
0.2

 

Carrying Costs Expense
 
(0.3
)
 
(0.2
)
 

Allowance for Equity Funds Used During Construction

52.2


53.0


44.8

Interest Expense

(50.3
)

(37.2
)

(23.5
)
Income Before Income Tax Expense and Equity Earnings

303.7


197.6


129.0

Income Tax Expense

134.1


91.3


62.9

Equity Earnings of Unconsolidated Subsidiaries

99.7


86.4


84.7

Net Income

269.3


192.7


150.8

Net Income Attributable to Noncontrolling Interests

3.0


1.5



Earnings Attributable to AEP Common Shareholders

$
266.3


$
191.2


$
150.8


Summary of Net Plant In Service and CWIP for AEP Transmission Holdco