Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended June 30, 2017
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____
Commission
 
Registrants; States of Incorporation;
 
I.R.S. Employer
File Number
 
Address and Telephone Number
 
Identification Nos.
 
 
 
 
 
1-3525
 
AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)
 
13-4922640
333-217143
 
AEP TRANSMISSION COMPANY, LLC (A Delaware Limited Liability Company)
 
46-1125168
1-3457
 
APPALACHIAN POWER COMPANY (A Virginia Corporation)
 
54-0124790
1-3570
 
INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)
 
35-0410455
1-6543
 
OHIO POWER COMPANY (An Ohio Corporation)
 
31-4271000
0-343
 
PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)
 
73-0410895
1-3146
 
SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)
 
72-0323455
 
 
1 Riverside Plaza, Columbus, Ohio 43215-2373
 
 
 
 
Telephone (614) 716-1000
 
 
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes x     No ¨
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate websites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes x     No ¨
Indicate by check mark whether the American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
 
Large Accelerated filer x             Accelerated filer ¨             Non-accelerated filer ¨   (Do not check if a smaller reporting company)
 
 
 
 
 
 
 
Smaller reporting company ¨
 
Emerging growth company ¨
 
 
 
Indicate by check mark whether AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
 
Large Accelerated filer ¨             Accelerated filer ¨             Non-accelerated filer   x   (Do not check if a smaller reporting company)
 
 
 
 
 
 
 
Smaller reporting company ¨
 
Emerging growth company ¨
 
 
 
 
If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
 
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act). Yes ¨      No x
AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.






 
Number of shares
of common stock
outstanding of the
Registrants as of
 
July 27, 2017
 
 
American Electric Power Company, Inc.
491,840,382

 
($6.50 par value)

AEP Transmission Company, LLC (a)
NA

 
 
Appalachian Power Company
13,499,500

 
(no par value)

Indiana Michigan Power Company
1,400,000

 
(no par value)

Ohio Power Company
27,952,473

 
(no par value)

Public Service Company of Oklahoma
9,013,000

 
($15 par value)

Southwestern Electric Power Company
7,536,640

 
($18 par value)


(a)
100% interest is held by AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of American Electric Power Company, Inc.
NA
Not applicable.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
June 30, 2017
 
 
 
 
 
 
 
 
 
Page
 
 
 
 
Number
Glossary of Terms
 
 
 
 
 
Forward-Looking Information
 
 
 
 
 
Part I. FINANCIAL INFORMATION
 
 
 
 
 
 
 
Items 1, 2, 3 and 4 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Controls and Procedures:
 
 
 
 
 
 
American Electric Power Company, Inc. and Subsidiary Companies:
 
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Condensed Consolidated Financial Statements
 
 
 
 
 
AEP Transmission Company, LLC and Subsidiaries:
 
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
Condensed Consolidated Financial Statements
 
 
 
 
 
Appalachian Power Company and Subsidiaries:
 
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
Condensed Consolidated Financial Statements
 
 
 
 
 
Indiana Michigan Power Company and Subsidiaries:
 
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
Condensed Consolidated Financial Statements
 
 
 
 
 
Ohio Power Company and Subsidiaries:
 
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
Condensed Consolidated Financial Statements
 
 
 
 
 
Public Service Company of Oklahoma:
 
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
Condensed Financial Statements
 
 
 
 
 
Southwestern Electric Power Company Consolidated:
 
 
Management’s Narrative Discussion and Analysis of Results of Operations
 
Condensed Consolidated Financial Statements
 
 
 
 
 
Index of Condensed Notes to Condensed Financial Statements of Registrants
 
 
 
 
 
Controls and Procedures




Part II.  OTHER INFORMATION
 
 
 
 
 
 
 
Item 1.
  Legal Proceedings
 
Item 1A.
  Risk Factors
 
Item 2.
  Unregistered Sales of Equity Securities and Use of Proceeds
 
Item 4.
  Mine Safety Disclosures
 
Item 5.
  Other Information
 
Item 6.
  Exhibits:
 
 
 
Exhibit 10
 
 
 
 
Exhibit 12
 
 
 
 
Exhibit 31(a)
 
 
 
 
Exhibit 31(b)
 
 
 
 
Exhibit 32(a)
 
 
 
 
Exhibit 32(b)
 
 
 
 
Exhibit 95
 
 
 
 
Exhibit 101.INS
 
 
 
 
Exhibit 101.SCH
 
 
 
 
Exhibit 101.CAL
 
 
 
 
Exhibit 101.DEF
 
 
 
 
Exhibit 101.LAB
 
 
 
 
Exhibit 101.PRE
 
 
 
 
 
 
SIGNATURE
 
 
 
 
 
 
 
 
 
 
 
 
This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company.  Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.




GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
Term
 
Meaning
 
 
 
AEGCo
 
AEP Generating Company, an AEP electric utility subsidiary.
AEP
 
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 Energy
 
AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.
AEP System
 
American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP Texas
 
AEP Texas Inc., an AEP electric utility subsidiary.
AEP Transmission Holdco
 
AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEPRO
 
AEP River Operations, LLC, a commercial barge operation sold in November 2015.
AEPSC
 
American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo
 
AEP Transmission Company, LLC, a subsidiary of AEP Transmission Holdco and an intermediate holding company that owns seven wholly-owned transmission companies.
AEPTCo Parent
 
AEP Transmission Company, LLC, the equity owner of the State Transcos within the AEPTCo consolidation.
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.
CAIR
 
Clean Air Interstate Rule
CO2
 
Carbon dioxide and other greenhouse gases.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,278 MW nuclear plant owned by I&M.
CWIP
 
Construction Work in Progress.
DCC Fuel
 
DCC Fuel VI LLC, DCC Fuel VII, DCC Fuel VIII, DCC Fuel IX and DCC Fuel X, consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC
 
Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
EIS
 
Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entity of AEP.
ENEC
 
Expanded Net Energy 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.

i



Term
 
Meaning
 
 
 
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.
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.
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.
MMBtu
 
Million British Thermal Units.
MPSC
 
Michigan Public Service Commission.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWh
 
Megawatthour.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NSR
 
New Source Review.
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.
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.
PJM
 
Pennsylvania – New Jersey – Maryland regional transmission organization.
PM
 
Particulate Matter.
PPA
 
Purchase Power and Sale Agreement.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants: AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants
 
SEC registrants: AEP, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.

ii



Term
 
Meaning
 
 
 
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
 
A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.  AEGCo and I&M jointly-own Unit 1.  In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
RSR
 
Retail Stability Rider.
RTO
 
Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine
 
Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC
 
U.S. Securities and Exchange Commission.
SEET
 
Significantly Excessive Earnings Test.
SNF
 
Spent Nuclear Fuel.
SO2
 
Sulfur dioxide.
SPP
 
Southwest Power Pool regional transmission organization.
SSO
 
Standard service offer.
State Transcos
 
AEPTCo’s seven wholly-owned, FERC-regulated, transmission-only electric utilities, each of which is geographically aligned with AEP existing utility operating companies.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC
 
Formerly AEP Texas Central Company, now a division of AEP Texas.
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.
Transition Funding
 
AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.
Transource Energy
 
Transource Energy, LLC, a consolidated variable interest entity formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.
Transource Missouri
 
A 100% wholly-owned subsidiary of Transource Energy.
Turk Plant
 
John W. Turk, Jr. Plant, a 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
Utility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
Virginia SCC
 
Virginia State Corporation Commission.
WPCo
 
Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC
 
Public Service Commission of West Virginia.
 

iii



FORWARD-LOOKING INFORMATION

This report made by 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” of the 2016 Annual Report and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in AEPTCo’s 2016 Annual Report included within AEPTCo’s Registration Statement, 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, the performance of generation plants and the availability of fuel, including processed nuclear fuel, parts and service from reliable vendors.
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.

iv



Ÿ
Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
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 the 2016 Annual Report and in Part II of this report. Additionally, see “Risk Factors” in the AEPTCo 2016 Annual Report included within AEPTCo’s Registration Statement.

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.

v





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

EXECUTIVE OVERVIEW

Customer Demand

AEP’s weather-normalized retail sales volumes for the second quarter of 2017 increased by 0.7% compared to second quarter of 2016. AEP’s second quarter 2017 industrial sales increased by 3.3% compared to the second quarter of 2016. The growth in industrial sales was spread across many industries and most operating companies. Weather-normalized residential sales increased 0.6% in the second quarter of 2017 compared to the second quarter of 2016. Weather-normalized commercial sales decreased by 1.9% in the second quarter of 2017 compared to the second quarter of 2016.

AEP’s weather-normalized retail sales volumes for the six months ended June 30, 2017 decreased by 0.2% compared to the six months ended June 30, 2016, partially due to 2016 being a leap year and including one additional day in comparison to 2017. AEP’s industrial sales volumes for the six months ended June 30, 2017 increased 1.6% compared to the six months ended June 30, 2016 primarily due to sales to customers in the manufacturing sector. Weather-normalized residential and commercial sales decreased 1.0% and 1.4%, respectively, for the six months ended June 30, 2017 compared to the six months ended June 30, 2016.

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. The sale closed in January 2017 for approximately $2.2 billion. The net proceeds from the transaction were 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 $129 million. AEP primarily used 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 6 for additional information.

In February 2017, AEP signed an agreement to sell its 25.4% ownership share of Zimmer Plant to Dynegy Corporation. Simultaneously, AEP signed an agreement to purchase Dynegy Corporation’s 40% ownership share of Conesville Plant, Unit 4. The transactions closed in the second quarter of 2017 and did not have a material impact on net income, cash flows and financial condition.

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. 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.


1



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.

Contracted Renewable Generation Facilities

AEP utilizes two 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 creditworthy counterparty.  AEP Renewables, LLC develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with credit-worthy counterparties. These subsidiaries have approximately 120 MWs of renewable generation projects in operation and 56 MWs of renewable generation projects under construction with an estimated financial commitment of approximately $317 million. As of June 30, 2017, $221 million of capital costs have been incurred related to these projects.

Regulated Renewable Generation Facilities

In July 2017, APCo submitted filings with the Virginia SCC and the WVPSC requesting regulatory approval to acquire two wind generation facilities totaling approximately 225 MW of wind generation. The wind generating facilities are located in West Virginia and Ohio and, if approved, are anticipated to be in-service in the second half of 2019. APCo will assume ownership of the facilities at or near the anticipated in-service date. APCo currently plans to sell the Renewable Energy Certificates associated with the generation from these facilities.

PSO and SWEPCo plan to submit filings with the OCC, LPSC, APSC, PUCT and the FERC requesting various regulatory approvals needed to fully proceed with the Wind Catcher Energy Connection project (Wind Catcher). The Wind Catcher project includes the acquisition of a wind generation facility, totaling approximately 2,000 MW of wind generation, and the construction of a generation interconnection tie-line totaling approximately 350 miles. Total investment for the project is estimated to be $4.5 billion. PSO and SWEPCo will have a 30% and 70% ownership share, respectively, in these assets. The wind generating facility is located in Oklahoma and, if approved by all state commissions and the FERC, is anticipated to be in-service by the end of 2020. In July 2017, the LPSC approved SWEPCo’s request for an exemption to the Market Based Mechanism.

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 (subject to prudence review) and through SWEPCo’s wholesale customers under FERC-based rates. As of June 30, 2017, 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.


2



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 a 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 Distribution Investment Rider (DIR) and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. A hearing at the PUCO is scheduled for August 2017.

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.

2016 SEET Filing

In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. See “2016 SEET Filing” section of Note 4.

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.  As of June 30, 2017, total costs incurred related to this project, including AFUDC, is approximately $9 million.  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 was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a request with the U.S. District Court for the Southern District of Ohio to delay the existing deadline for installation of SCR technology at Rockport Plant, Unit 2.


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2017 Indiana Base Rate Case

In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to an offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures.  The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Life Cycle Management Project.

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

2017 Michigan Base Rate Case

In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than March 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related primarily to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses.

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

Louisiana Turk Plant Prudence Review

Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29%) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012.
 
A hearing at the LPSC related to the Turk Plant prudence review is scheduled for November 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.

2017 Oklahoma Base Rate Case

In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure deployment cost, (c) additional capital investments and customer costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, PSO also requested recovery through 2040 of the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of June 30, 2017, the net book value of Northeastern Plant, Unit 4 was $83 million, before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


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2017 Kentucky Base Rate Case

In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

FERC Transmission Complaint - AEP’s PJM Participants

In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various eastern 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. Management believes its financial statements adequately address the impact of the complaint. 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.

Modifications to AEP’s PJM Transmission Rates

In November 2016, certain AEP affiliates filed an application with the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the modified PJM OATT formula rates were implemented, subject to refund, based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

FERC Transmission Complaint - AEP’s SPP Participants

In June 2017, several parties filed a joint complaint with the FERC that states the base return on common equity used by western AEP affiliates in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. 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.

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 total approximately $850 million, excluding AFUDC. As of June 30, 2017, SWEPCo had incurred costs of $398 million, including AFUDC, related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of June 30, 2017, the total net book value of Welsh Plant, Units 1 and 3 was $628 million, before cost of removal, including materials and supplies inventory and CWIP. 

In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In April 2017, the LPSC approved SWEPCo’s recovery of $131 million in investments related to Louisiana’s jurisdictional share of environmental costs, effective May 2017.   SWEPCo has sought recovery of its project costs from retail customers at the PUCT and is recovering these costs from wholesale customers through their FERC-approved agreements. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See “Welsh Plant - Environmental Impact” section of Note 4.

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Westinghouse Electric Company Bankruptcy Filing

In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code.  It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize.  Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects.  The most significant of these relate to Cook Plant fuel fabrication.  I&M is evaluating how this reorganization affects these contracts.  Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M continues to work with Westinghouse in the bankruptcy proceedings to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services.

Ohio Distribution Base Rates

In December 2011, OPCo’s current distribution base rates were approved by the PUCO in OPCo’s most recent distribution base rate case.  The December 2011 base case order also included the PUCO’s approval for OPCo to record amortization of an excess distribution accumulated depreciation reserve of approximately $39 million per year from January 2012 through December 2018. As of June 30, 2017, the balance of the unamortized accumulated depreciation reserve is $58 million.
 
In February 2017, the PUCO approved a stipulation agreement regarding OPCo’s proposal to extend the smart grid project involving the installation of advanced metering infrastructure and distribution automation technology throughout parts of OPCo’s service territory (smart grid Phase 2).  As a condition of the smart grid Phase 2 stipulation agreement, OPCo must submit a distribution base rate case filing within six months of the completion of the smart grid Phase 2 program. 

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, Note 6 - Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2016 Annual Report. Additionally, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies included herein. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs.  The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.  In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. 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

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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 plaintiffs 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 plaintiffs’ 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 an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in 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. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings.  The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree.

ENVIRONMENTAL ISSUES

AEP has a substantial capital investment program and is 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 new CAA requirements to reduce emissions 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.  Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2016 Annual Report. 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.

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Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of June 30, 2017, the AEP System had a total generating capacity of approximately 25,600 MWs, of which approximately 13,500 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 $2.2 billion to $2.8 billion between 2017 and 2025.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or reviewing and revising certain existing requirements.  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.

The table below represents the plants or units of plants retired in 2016 and 2015 with a remaining net book value. As of June 30, 2017, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of the units listed below was approved for recovery, except for $339 million. Management will seek recovery of the remaining net book value associated with these plants in future rate proceedings.
 
 
 
 
Generating
 
Amounts Pending
Company
 
Plant Name and Unit
 
Capacity
 
Regulatory Approval
 
 
 
 
(in MWs) 
 
 
APCo
 
Kanawha River Plant
 
400

 
$
42.3

APCo
 
Clinch River Plant, Unit 3
 
235

 
32.7

APCo (a)
 
Clinch River Plant, Units 1 and 2
 
470

 
31.8

APCo
 
Sporn Plant
 
600

 
17.2

APCo
 
Glen Lyn Plant
 
335

 
13.4

I&M
 
Tanners Creek Plant
 
995

 
42.6

PSO (b)
 
Northeastern Station, Unit 4
 
470

 
83.3

SWEPCo (c)
 
Welsh Plant, Unit 2
 
528

 
75.9

Total
 
 
 
4,033

 
$
339.2


(a)
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 2015, APCo retired the coal-related assets of Clinch River Plant, Units 1 and 2. Clinch River Plant, Unit 1 and Unit 2 began operations as natural gas units in February 2016 and April 2016, respectively.
(b)
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. This regulatory asset is pending regulatory approval. In June 2017, PSO filed an application for a base rate review with the OCC. As part of this filing, PSO requested recovery of approximately $83 million through 2040 related to the net book value of Northeastern Plant, Unit 4 that was retired in 2016.
(c)
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. This regulatory asset is pending regulatory approval.

In January 2017, Dayton Power and Light Company 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 Company and are jointly owned by AGR and nonaffiliated entities. AGR owns 600 MWs of the Stuart Plant, Units 1-4. As of June 30, 2017, AGR’s net book value of the Stuart Plant, Units 1-4 was zero.


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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.

Proposed Modification of the New Source Review (NSR) Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between the AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when it undertook various equipment repair and replacement projects over a period of nearly 20 years.  The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOx emissions from the AEP System and various mitigation projects.

In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate an obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree.  AEP has also sought to delay the existing deadline to install SCR technology at Rockport Plant, Unit 2, currently scheduled to be installed by December 2019, pending resolution of the motion.  AEP also proposes to retire Conesville Plant, Units 5 and 6 by December 31, 2022 and to retire one Rockport Plant unit by December 31, 2028.

AEP is seeking to modify the consent decree as a means to resolve or substantially narrow the issues in pending litigation with the owners of Rockport Unit 2. See “Rockport Plant Litigation” in Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 5 - Commitments, Guarantees and Contingencies for additional information.

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 primary regulatory programs that continue to drive investments in AEP’s existing generating units include: (a) periodic revisions to the National Ambient Air Quality Standards (NAAQS) and the development of SIPs to achieve any more stringent standards; (b) implementation of the regional haze program by the states and the Federal EPA; (c) regulation of hazardous air pollutant emissions under the Mercury and Air Toxics Standards (MATS) Rule; (d) implementation and review of the Cross-State Air Pollution Rule (CSAPR), a FIP designed to eliminate significant contributions from sources in upwind states to nonattainment or maintenance areas in downwind states and (e) the Federal EPA’s regulation of greenhouse gas emissions from fossil-fueled electric generating units under Section 111 of the CAA.

In March 2017, President Trump issued a series of executive orders designed to allow the Federal EPA to review and take appropriate action to revise or rescind regulatory requirements that place undue burdens on affected entities, including specific orders directing the Federal EPA to review rules that unnecessarily burden the production and use of energy. The Federal EPA published notice and an opportunity to comment on how to identify such requirements and what steps can be taken to reduce or eliminate such burdens. Future changes that result from this effort may affect AEP’s compliance plans.

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

National Ambient Air Quality Standards (NAAQS)

The Federal EPA issued new, more stringent NAAQS for SO2 in 2010, PM in 2012 and ozone in 2015. Implementation of these standards is underway. States are still in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the 2010 SO2 NAAQS and may develop additional requirements for AEP’s facilities as a result of those evaluations. In April 2017, the Federal EPA requested a stay of proceedings in the U.S. Court of Appeals for the District of Columbia Circuit where challenges to the 2015 ozone standard are pending, to allow reconsideration of that standard by the new administration. The Federal EPA also announced a one-year delay

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in the formal designation of ozone non-attainment areas in order to conduct a more complete evaluation of available information. Management cannot currently predict the nature, stringency or timing of additional requirements for AEP’s facilities based on the outcome of these activities.

Regional Haze

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. Petitions for review of the final rule revisions have been filed in the U.S. Court of Appeals for the District of Columbia Circuit.

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 March 2017, the Federal EPA filed a motion that was granted by the U.S. Court of Appeals for the Eighth Circuit Court to hold the case in abeyance for 90 days to allow the parties to engage in settlement negotiations. Management cannot predict the outcome of these proceedings.

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 March 2017, the U.S. Court of Appeals for the Fifth Circuit granted partial remand of the final rule. In January 2017, Federal EPA proposed source-specific BART requirements for SO2 from sources in Texas, including Welsh Plant, Unit 1. Management submitted comments on the proposal and is engaged in discussions with the Texas Commission on Environmental Quality regarding the development of an alternative to source-specific BART.

In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the CSAPR trading programs to use those programs in place of source-specific BART for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states.  This rule is being challenged in the U.S. Court of Appeals for the District of Columbia Circuit. In November 2016, the Federal EPA proposed to remove Texas from the annual SO2 and NOx budget programs. Management supports compliance with CSAPR programs as satisfaction of the BART requirements.

Cross-State Air Pollution Rule (CSAPR)

In 2011, the Federal EPA issued CSAPR as a replacement for the CAIR, a regional trading program designed to address interstate transport of emissions that contributed significantly to downwind nonattainment with the 1997 ozone and PM NAAQS.  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.  

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. The court stayed implementation of the rule.  Following extended proceedings in the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court, but while the litigation was still pending, the U.S. Court of Appeals for the District of Columbia Circuit granted the Federal EPA’s 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. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit found that the Federal EPA over-

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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 October 2016, a final rule was issued to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The final rule 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 is complying with the more stringent ozone season budgets while these petitions are being considered.

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.  Compliance was required within three years. Management obtained administrative extensions for up to one year 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 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. Oral argument was scheduled for May 2017, but in April 2017 the Federal EPA requested that oral argument be postponed to facilitate its review of the rule. 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.

11



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. In June 2016, the Federal EPA issued a separate proposal for the Clean Energy Incentive Program (CEIP) that was included in the model rules.

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.

In March 2017, the Federal EPA filed in the U.S. Court of Appeals for the District of Columbia Circuit notice of 1) an Executive Order from the President of the United States titled “Promoting Energy Independence and Economic Growth” directing the Federal EPA to review the Clean Power Plan and related rules; 2) the Federal EPA’s initiation of a review of the Clean Power Plan and 3) if the Federal EPA determines appropriate, a forthcoming rulemaking related to the Clean Power Plan consistent with the Executive Order. In this same filing, the Federal EPA also presented a motion to hold the litigation in abeyance until 30 days after the conclusion of review and any resulting rulemaking. In April 2017, the Federal EPA withdrew its previously issued proposals for model trading rules and a CEIP.

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 to be implemented on a schedule spanning an approximate four year implementation period.

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.

Clean Water Act (CWA) Regulations

In 2014, the Federal EPA issued a final rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The final rule affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to comply with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures at facilities withdrawing more than

12



125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, are not expected to require any technology changes. Facilities subject to both the impingement standard and site-specific entrainment studies will typically be given at least three years to conduct and submit the results of those studies to the permit agency. Compliance timeframes will then be established by the permit agency through each facility’s National Pollutant Discharge Elimination System (NPDES) permit for installation of any required technology changes, as those permits are renewed over the next five to eight years. Petitions for review of the final rule were filed by industry and environmental groups and are currently pending in the U.S. Court of Appeals for the Second Circuit.

In addition, the Federal EPA developed revised effluent limitation guidelines for electricity generating facilities.  A final rule was issued in November 2015. The final rule establishes limits on flue gas desulfurization wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater 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. The rule has been challenged in the U.S. Court of Appeals for the Fifth Circuit. In March 2017, industry associations filed a petition for reconsideration of the rule with the Federal EPA. In April 2017, the Federal EPA granted reconsideration of the rule and issued a stay of the rule’s future compliance deadlines. In April 2017, the U.S. Court of Appeals for the Fifth Circuit granted a stay of the litigation for 120 days. In June 2017, the Federal EPA also issued a proposal to temporarily postpone certain compliance deadlines in the rule. Management submitted comments supporting the proposed postponement. Management continues to assess technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge permitting.

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. The U.S. Supreme Court denied the Federal EPA’s motion to hold briefing in abeyance pending further Federal EPA actions on the rule and the appeal on the jurisdictional issue continues.

In March 2017, the Federal EPA published a notice of intent to review the rule and provide an advanced notice of a proposed rulemaking consistent with the Executive Order of the President of the United States directing the Federal EPA and U.S. Army Corps of Engineers to review and rescind or revise the rule. In June 2017, the agencies signed a notice of proposed rule to rescind the definition of “waters of the United States” that was adopted in June 2015, and to re-codify the definition of that phrase as it existed immediately prior to that action. This action would effectively retain the status quo until a new rule is adopted by the agencies.
  

13



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 AEPTCo. These investments have FERC-approved returns on equity.
Development, construction and operation of transmission facilities through investments in AEP’s 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.

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.
  

14



The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
 
(in millions)
Vertically Integrated Utilities
$
120.8

 
$
209.4

 
$
340.3

 
$
487.0

Transmission and Distribution Utilities
111.2

 
124.6

 
230.3

 
232.1

AEP Transmission Holdco
128.4

 
94.6

 
200.2

 
138.5

Generation & Marketing
26.4

 
49.7

 
212.6

 
120.4

Corporate and Other
(11.8
)
 
23.8

 
(16.2
)
 
25.3

Earnings Attributable to AEP Common Shareholders
$
375.0

 
$
502.1

 
$
967.2

 
$
1,003.3


AEP CONSOLIDATED

Second Quarter of 2017 Compared to Second Quarter of 2016

Earnings Attributable to AEP Common Shareholders decreased from income of $502 million in 2016 to income of $375 million in 2017 primarily due to:

A decrease in generation revenues associated with the sale of certain merchant generation assets.
A decrease in FERC wholesale municipal and cooperative revenues.
A decrease in weather-related usage.
The prior year reversal of income tax expense for an unrealized capital loss valuation allowance. AEP effectively settled a 2011 audit issue with the IRS resulting in a change in the valuation allowance.

These decreases were partially offset by:

An increase in transmission investment primarily at AEP Transmission Holdco which resulted in higher revenues and income.
Favorable rate proceedings in AEP’s various jurisdictions.

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

Earnings Attributable to AEP Common Shareholders decreased from income of $1.0 billion in 2016 to income of $967 million in 2017 primarily due to:

A decrease in generation revenues associated with the sale of certain merchant generation assets.
A decrease in weather-related usage.
A decrease in FERC wholesale municipal and cooperative revenues.
The prior year reversal of income tax expense for an unrealized capital loss valuation allowance. AEP effectively settled a 2011 audit issue with the IRS resulting in a change in the valuation allowance.

These decreases were partially offset by:

A gain resulting from the sale of certain merchant generation assets.
An increase in transmission investment primarily at AEP Transmission Holdco which resulted in higher revenues and income.
Favorable rate proceedings in AEP’s various jurisdictions.

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

15



VERTICALLY INTEGRATED UTILITIES
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 Vertically Integrated Utilities
 
2017
 
2016
 
2017
 
2016
 
 
(in millions)
Revenues
 
$
2,120.5

 
$
2,125.9

 
$
4,410.9

 
$
4,371.5

Fuel and Purchased Electricity
 
711.9

 
699.5

 
1,500.3

 
1,441.5

Gross Margin
 
1,408.6

 
1,426.4

 
2,910.6

 
2,930.0

Other Operation and Maintenance
 
711.2

 
624.3

 
1,365.4

 
1,253.9

Depreciation and Amortization
 
278.0

 
271.0

 
556.3

 
537.8

Taxes Other Than Income Taxes
 
99.4

 
98.1

 
200.5

 
196.0

Operating Income
 
320.0

 
433.0

 
788.4

 
942.3

Interest and Investment Income
 
1.0

 
1.0

 
4.1

 
1.6

Carrying Costs Income
 
5.1

 
5.1

 
9.2

 
7.3

Allowance for Equity Funds Used During Construction
 
6.3

 
10.6

 
12.5

 
25.4

Interest Expense
 
(136.7
)
 
(135.9
)
 
(271.6
)
 
(263.2
)
Income Before Income Tax Expense and Equity Earnings (Loss)
 
195.7

 
313.8

 
542.6

 
713.4

Income Tax Expense
 
68.1

 
104.5

 
195.8

 
226.4

Equity Earnings (Loss) of Unconsolidated Subsidiaries
 
(6.2
)
 
1.2

 
(4.9
)
 
2.2

Net Income
 
121.4

 
210.5

 
341.9

 
489.2

Net Income Attributable to Noncontrolling Interests
 
0.6

 
1.1

 
1.6

 
2.2

Earnings Attributable to AEP Common Shareholders
 
$
120.8

 
$
209.4

 
$
340.3

 
$
487.0


Summary of KWh Energy Sales for Vertically Integrated Utilities
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
 
(in millions of KWhs)
Retail:
 

 
 

 
 

 
 

Residential
6,499

 
6,674

 
14,738

 
15,798

Commercial
5,996

 
6,190

 
11,685

 
12,070

Industrial
8,689

 
8,654

 
16,953

 
16,921

Miscellaneous
562

 
565

 
1,098

 
1,106

Total Retail
21,746

 
22,083

 
44,474

 
45,895

 
 
 
 
 
 
 
 
Wholesale (a)
5,918

 
5,696

 
12,425

 
10,488

 
 
 
 
 
 
 
 
Total KWhs
27,664

 
27,779

 
56,899

 
56,383

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


16



Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.  In general, degree day changes in 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
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
 
(in degree days)
Eastern Region
 

 
 

 
 

 
 

Actual  Heating (a)
85

 
164

 
1,266

 
1,684

Normal  Heating (b)
138

 
137

 
1,753

 
1,770

 
 
 
 
 
 
 
 
Actual  Cooling (c)
335

 
347

 
336

 
352

Normal  Cooling (b)
324

 
327

 
329

 
332

 
 
 
 
 
 
 
 
Western Region
 

 
 

 
 

 
 

Actual  Heating (a)
9

 
7

 
539

 
685

Normal  Heating (b)
33

 
34

 
925

 
926

 
 
 
 
 
 
 
 
Actual  Cooling (c)
637

 
713

 
719

 
743

Normal  Cooling (b)
696

 
693

 
720

 
716


(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.



17



Second Quarter of 2017 Compared to Second Quarter of 2016
Reconciliation of Second Quarter of 2016 to Second Quarter of 2017
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
 
 
 
Second Quarter of 2016
 
$
209.4

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
(36.6
)
Off-system Sales
 
4.0

Transmission Revenues
 
12.5

Other Revenues
 
2.3

Total Change in Gross Margin
 
(17.8
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(86.9
)
Depreciation and Amortization
 
(7.0
)
Taxes Other Than Income Taxes
 
(1.3
)
Allowance for Equity Funds Used During Construction
 
(4.3
)
Interest Expense
 
(0.8
)
Total Change in Expenses and Other
 
(100.3
)
 
 
 

Income Tax Expense
 
36.4

Equity Earnings (Loss)
 
(7.4
)
Net Income Attributable to Noncontrolling Interests
 
0.5

 
 
 
Second Quarter of 2017
 
$
120.8


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

Retail Margins decreased $37 million primarily due to the following:
A $39 million decrease in FERC wholesale municipal and cooperative revenues primarily due to formula rate adjustments at I&M and SWEPCo.
A $25 million decrease in weather-related usage in the eastern and western regions.
A $17 million decrease primarily due to prior year recognition of deferred billing in West Virginia as approved by the WVPSC which is partially offset by increases in rates in West Virginia.
A $6 million decrease in weather-normalized margins primarily in the commercial and industrial classes partially offset by an increase in the residential class.
These decreases were partially offset by:
The effect of rate proceedings in AEP’s service territories which included:
A $16 million increase from rate proceedings in the Indiana service territory.
A $14 million increase primarily due to revenue increases from rate riders in Louisiana and Texas.
For the rate increases described above, $15 million relate to riders/trackers which have corresponding increases in expense items below.
A $6 million increase primarily due to reduced fuel and other variable production costs not recovered through fuel clauses or other trackers.
Margins from Off-system Sales increased $4 million primarily due to higher market prices.
Transmission Revenues increased $13 million primarily due to the formula rate increase driven by continued investment in transmission assets.


18



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

Other Operation and Maintenance expenses increased $87 million primarily due to the following:
A $69 million increase in recoverable expenses, primarily including PJM expenses, energy efficiency expenses and vegetation management expenses fully recovered in rate recovery riders/trackers within Gross Margin above.
An $8 million increase in PJM and SPP transmission services expense not recovered through riders/trackers.
A $6 million increase in vegetation management expenses primarily at I&M and PSO.
A $6 million increase due to a gain on the sale of property at APCo in 2016.
Depreciation and Amortization expenses increased $7 million primarily due to the following:
A $14 million increase primarily due to higher depreciable base.
A $4 million increase due to amortization of capitalized software costs.
These increases were partially offset by:
A $9 million decrease primarily related to prior year higher estimated depreciation expense associated with interim rates at PSO.
Allowance for Equity Funds Used During Construction decreased $4 million primarily due to completed environmental projects.
Income Tax Expense decreased $36 million primarily due to a decrease in pretax book income.
Equity Earnings (Loss) decreased $7 million primarily due to a prior period income tax adjustment for DHLC, a SWEPCo unconsolidated subsidiary.

19



Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016
Reconciliation of Six Months Ended June 30, 2016 to Six Months Ended June 30, 2017
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
 
 
 
Six Months Ended June 30, 2016
 
$
487.0

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
(49.7
)
Off-system Sales
 
8.2

Transmission Revenues
 
18.5

Other Revenues
 
3.6

Total Change in Gross Margin
 
(19.4
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
(111.5
)
Depreciation and Amortization
 
(18.5
)
Taxes Other Than Income Taxes
 
(4.5
)
Interest and Investment Income
 
2.5

Carrying Costs Income
 
1.9

Allowance for Equity Funds Used During Construction
 
(12.9
)
Interest Expense
 
(8.4
)
Total Change in Expenses and Other
 
(151.4
)
 
 
 

Income Tax Expense
 
30.6

Equity Earnings (Loss)
 
(7.1
)
Net Income Attributable to Noncontrolling Interests
 
0.6

 
 
 
Six Months Ended June 30, 2017
 
$
340.3


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

Retail Margins decreased $50 million primarily due to the following:
An $83 million decrease in weather-related usage primarily in the eastern region.
A $37 million decrease in FERC wholesale municipal and cooperative revenues primarily due to formula rate adjustments at I&M and SWEPCo.
An $18 million decrease in weather-normalized margins primarily in the commercial and industrial classes partially offset by an increase in the residential class.
An $8 million decrease primarily due to prior year recognition of deferred billing in West Virginia as approved by the WVPSC which is partially offset by increases in rates in Virginia and West Virginia.
These decreases were partially offset by:
The effect of rate proceedings in AEP’s service territories which included:
A $34 million increase from rate proceedings in the Indiana service territory.
A $21 million increase due to revenue increases from rate riders in Louisiana, Texas and Arkansas.
An $8 million increase for PSO due to revenue increases from rate riders/trackers.
A $5 million increase for KPCo and KGPCo due to revenue increases from rate riders/trackers.
For the rate increases described above, $34 million relate to riders/trackers which have corresponding increases in expense items below.
A $17 million increase primarily due to reduced fuel and other variable production costs not recovered through fuel clauses or other trackers.
Margins from Off-system Sales increased $8 million primarily due to higher market prices and decreased internal loads.
Transmission Revenues increased $19 million primarily due to the formula rate increase driven by continued investment in transmission assets.

20



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

Other Operation and Maintenance expenses increased $112 million primarily due to the following:
A $101 million increase in recoverable expenses, primarily including PJM expenses, energy efficiency expenses and vegetation management expenses fully recovered in rate recovery riders/trackers within Gross Margin above.
A $19 million increase in vegetation management expenses primarily at PSO and I&M.
These increases were partially offset by:
A $12 million decrease in employee-related expenses.
Depreciation and Amortization expenses increased $19 million primarily due to the following:
A $30 million increase primarily due to higher depreciable base.
A $9 million increase due to amortization of capitalized software costs.
These increases were partially offset by:
A $15 million decrease primarily related to prior year higher estimated depreciation expense associated with interim rates at PSO.
Taxes Other Than Income Taxes increased $5 million primarily due to higher property taxes.
Allowance for Equity Funds Used During Construction decreased $13 million primarily due to completed environmental projects.
Interest Expense increased $8 million primarily due to the following:
A $6 million increase due to lower AFUDC borrowed funds resulting from completed environmental projects.
A $4 million increase primarily due to higher long-term debt balances at I&M.
Income Tax Expense decreased $31 million primarily due to a decrease in pretax book income partially offset by other book/tax differences which are accounted for on a flow-through basis and by the recording of favorable state and federal income tax adjustments in 2016.
Equity Earnings (Loss) decreased $7 million primarily due to a prior period income tax adjustment for DHLC, a SWEPCo unconsolidated subsidiary.


21



TRANSMISSION AND DISTRIBUTION UTILITIES
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Transmission and Distribution Utilities
 
2017
 
2016
 
2017
 
2016
 
 
(in millions)
Revenues
 
$
1,053.5

 
$
1,096.1

 
$
2,139.9

 
$
2,192.9

Purchased Electricity
 
186.9

 
191.0

 
410.3

 
408.6

Amortization of Generation Deferrals
 
53.3

 
51.8

 
114.2

 
106.9

Gross Margin
 
813.3

 
853.3

 
1,615.4

 
1,677.4

Other Operation and Maintenance
 
293.6

 
325.8

 
579.3

 
651.3

Depreciation and Amortization
 
163.9

 
167.3

 
320.1

 
323.6

Taxes Other Than Income Taxes
 
126.6

 
117.7

 
253.5

 
241.0

Operating Income
 
229.2

 
242.5

 
462.5

 
461.5

Interest and Investment Income
 
0.9

 
1.5

 
4.4

 
4.0

Carrying Costs Income
 
0.6

 
1.2

 
2.5

 
3.1

Allowance for Equity Funds Used During Construction
 
1.2

 
4.1

 
5.4

 
8.4

Interest Expense
 
(61.5
)
 
(65.5
)
 
(121.5
)
 
(132.8
)
Income Before Income Tax Expense
 
170.4

 
183.8

 
353.3

 
344.2

Income Tax Expense
 
59.2

 
59.2

 
123.0

 
112.1

Net Income
 
111.2

 
124.6

 
230.3

 
232.1

Net Income Attributable to Noncontrolling Interests
 

 

 

 

Earnings Attributable to AEP Common Shareholders
 
$
111.2

 
$
124.6

 
$
230.3

 
$
232.1


Summary of KWh Energy Sales for Transmission and Distribution Utilities
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
 
(in millions of KWhs)
Retail:
 

 
 

 
 

 
 

Residential
5,956

 
6,009

 
11,850

 
12,250

Commercial
6,490

 
6,602

 
12,243

 
12,389

Industrial
5,941

 
5,506

 
11,417

 
11,004

Miscellaneous
171

 
175

 
331

 
341

Total Retail (a)
18,558

 
18,292

 
35,841

 
35,984

 
 
 
 
 
 
 
 
Wholesale (b)
761

 
412

 
1,559

 
735

 
 
 
 
 
 
 
 
Total KWhs
19,319

 
18,704

 
37,400

 
36,719


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


22



Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.  In general, degree day changes in 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
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
 
(in degree days)
Eastern Region
 

 
 

 
 

 
 

Actual  Heating (a)
97

 
238

 
1,500

 
1,929

Normal  Heating (b)
186

 
184

 
2,085

 
2,103

 
 
 
 
 
 
 
 
Actual  Cooling (c)
312

 
308

 
315

 
309

Normal  Cooling (b)
287

 
289

 
290

 
292

 
 
 
 
 
 
 
 
Western Region
 

 
 

 
 

 
 

Actual  Heating (a)
1

 
2

 
103

 
123

Normal  Heating (b)
4

 
4

 
199

 
198

 
 
 
 
 
 
 
 
Actual  Cooling (d)
989

 
926

 
1,247

 
1,085

Normal  Cooling (b)
919

 
917

 
1,032

 
1,026


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


23



Second Quarter of 2017 Compared to Second Quarter of 2016
Reconciliation of Second Quarter of 2016 to Second Quarter of 2017
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
 
 
 
Second Quarter of 2016
 
$
124.6

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
(44.9
)
Off-system Sales
 
(7.6
)
Transmission Revenues
 
7.5

Other Revenues
 
5.0

Total Change in Gross Margin
 
(40.0
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
32.2

Depreciation and Amortization
 
3.4

Taxes Other Than Income Taxes
 
(8.9
)
Interest and Investment Income
 
(0.6
)
Carrying Costs Income
 
(0.6
)
Allowance for Equity Funds Used During Construction
 
(2.9
)
Interest Expense
 
4.0

Total Change in Expenses and Other
 
26.6

 
 
 

Income Tax Expense
 

 
 
 

Second Quarter of 2017
 
$
111.2


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

Retail Margins decreased $45 million primarily due to the following:
A $42 million decrease in Ohio revenues associated with the Universal Service Fund (USF) surcharge rate decrease. This decrease was offset by a corresponding decrease in Other Operating and Maintenance expenses below.
A $21 million decrease due to a prior year reversal of a regulatory provision resulting from a favorable court decision in Ohio.
An $8 million decrease in weather-normalized margins primarily in the residential and commercial classes.
A $5 million decrease in revenues associated with smart grid riders in Ohio. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
These decreases were partially offset by:
An $18 million favorable impact in Ohio due to the recovery of losses from a power contract with OVEC. The PUCO approved a PPA rider beginning in January 2017 to recover any net margin related to the deferral of OVEC losses starting in June 2016. This increase was offset by a corresponding decrease in Margins from Off-System Sales below.
A $14 million increase in AEP Texas revenues associated with the Distribution Cost Recovery Factor revenue rider.
Margins from Off-system Sales decreased $8 million primarily due to the following:
An $18 million decrease in Ohio due to current year losses from a power contract with OVEC which is deferred in Retail Margins above as a result of the OVEC PPA rider beginning in January 2017.
This decrease was partially offset by:
A $10 million increase in Ohio primarily due to the impact of prior year losses from a power contract with OVEC which was not included in the OVEC PPA rider.

24



Transmission Revenues increased $8 million primarily due to recovery of increased transmission investment in ERCOT.
Other Revenues increased $5 million primarily due to the following:
A $3 million increase in Texas securitization revenue, offset in other expense items below.
A $2 million increase in Ohio pole attachment revenue.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses decreased $32 million primarily due to the following:
A $42 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.
A $5 million decrease in recoverable smart grid rider expenses in Ohio. This decrease was offset by a corresponding decrease in Retail Margins above.
A $5 million decrease in Energy Efficiency/Peak Demand Reduction and PJM expenses. This decrease was offset by a corresponding decrease in Retail Margins above.
These decreases were partially offset by:
An $11 million increase in PJM transmission services expense related to the annual formula rate true-up that will be recovered in future periods.
A $3 million increase in uncollectible expenses related to pole attachments in Ohio.
A $2 million increase in vegetation management expenses.
Taxes Other Than Income Taxes increased $9 million primarily due to increased property taxes as a result of additional capital investment and increased tax rates.
Interest Expense decreased $4 million primarily due to the following:
A $3 million decrease due to the maturity of a senior unsecured note in June 2016 in Ohio.
A $2 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.

25



Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016
Reconciliation of Six Months Ended June 30, 2016 to Six Months Ended June 30, 2017
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
 
 
 
Six Months Ended June 30, 2016
 
$
232.1

 
 
 

Changes in Gross Margin:
 
 

Retail Margins
 
(64.4
)
Off-system Sales
 
(15.2
)
Transmission Revenues
 
16.7

Other Revenues
 
0.9

Total Change in Gross Margin
 
(62.0
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
72.0

Depreciation and Amortization
 
3.5

Taxes Other Than Income Taxes
 
(12.5
)
Interest and Investment Income
 
0.4

Carrying Costs Income
 
(0.6
)
Allowance for Equity Funds Used During Construction
 
(3.0
)
Interest Expense
 
11.3

Total Change in Expenses and Other
 
71.1

 
 
 

Income Tax Expense
 
(10.9
)
 
 
 

Six Months Ended June 30, 2017
 
$
230.3


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

Retail Margins decreased $64 million primarily due to the following:
An $88 million decrease in Ohio revenues associated with the USF surcharge rate decrease. This decrease was offset by a corresponding decrease in Other Operating and Maintenance expenses below.
A $23 million decrease in weather-normalized margins, primarily in the residential class.
A $21 million decrease due to a prior year reversal of a regulatory provision resulting from a favorable court decision in Ohio.
These decreases were partially offset by:
A $34 million favorable impact in Ohio due to the recovery of losses from a power contract with OVEC. The PUCO approved a PPA rider beginning in January 2017 to recover any net margin related to the deferral of OVEC losses starting in June 2016. This increase was offset by a corresponding decrease in Margins from Off-System Sales below.
A $26 million increase in AEP Texas revenues associated with the Distribution Cost Recovery Factor revenue rider.
A $15 million net increase in Ohio Phase-In Recovery Rider revenue less associated amortizations.
Margins from Off-system Sales decreased $15 million primarily due to the following:
A $34 million decrease in Ohio due to current year losses from a power contract with OVEC, which is deferred in Retail Margins above as a result of the OVEC PPA rider beginning in January 2017.
This decrease was partially offset by:
An $18 million increase in Ohio primarily due to the impact of prior year losses from a power contract with OVEC which was not included in the OVEC PPA rider.
Transmission Revenues increased $17 million primarily due to recovery of increased transmission investment in ERCOT.

26



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

Other Operation and Maintenance expenses decreased $72 million primarily due to the following:
An $88 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.
These decreases were partially offset by:
A $10 million increase in PJM expenses related to the annual formula rate true-up that will be recovered in future periods.
A $5 million increase in vegetation management expenses.
Depreciation and Amortization expenses decreased $4 million primarily due to the following:
A $7 million decrease due to recoveries of transmission cost rider carrying costs in Ohio. This decrease was partially offset in Retail Margins above.
A $7 million decrease in amortization expenses for the collection of carrying costs on Ohio deferred capacity charges beginning June 2015.
These increases were partially offset by:
A $10 million increase in depreciation expense primarily due to an increase in depreciable base of transmission and distribution assets.
Taxes Other Than Income Taxes increased $13 million primarily due to increased property taxes as a result of additional transmission and distribution investment and increasing tax rates.
Interest Expense decreased $11 million primarily due to the following:
A $9 million decrease due to the maturity of a senior unsecured note in June 2016 in Ohio.
A $4 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.
Income Tax Expense increased $11 million primarily due to the recording of favorable state income tax adjustments in 2016 and an increase in pretax book income.

27



AEP TRANSMISSION HOLDCO
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
AEP Transmission Holdco
 
2017
 
2016
 
2017
 
2016
 
 
(in millions)
Transmission Revenues
 
$
247.3

 
$
161.7

 
$
403.4

 
$
250.3

Other Operation and Maintenance
 
17.4

 
8.8

 
31.4

 
20.5

Depreciation and Amortization
 
24.0

 
15.8

 
48.6

 
31.3

Taxes Other Than Income Taxes
 
28.4

 
21.8

 
56.4

 
43.0

Operating Income
 
177.5

 
115.3

 
267.0

 
155.5

Interest and Investment Income
 
0.2

 
0.2

 
0.4

 
0.2

Carrying Costs Expense
 
(0.1
)
 
(0.2
)
 
(0.1
)
 
(0.2
)
Allowance for Equity Funds Used During Construction
 
13.5

 
13.9

 
24.3

 
26.3

Interest Expense
 
(17.1
)
 
(11.6
)
 
(34.4
)
 
(23.4
)
Income Before Income Tax Expense and Equity Earnings
 
174.0

 
117.6

 
257.2

 
158.4

Income Tax Expense
 
67.1

 
47.6

 
103.5

 
68.0

Equity Earnings of Unconsolidated Subsidiaries
 
22.1

 
25.3

 
48.1

 
49.6

Net Income
 
129.0

 
95.3

 
201.8

 
140.0

Net Income Attributable to Noncontrolling Interests
 
0.6

 
0.7

 
1.6

 
1.5

Earnings Attributable to AEP Common Shareholders
 
$
128.4

 
$
94.6

 
$
200.2

 
$
138.5


Summary of Investment in Transmission Assets for AEP Transmission Holdco
 
 
June 30,
 
 
2017
 
2016
 
 
(in millions)
Plant in Service
 
$
4,809.2

 
$
3,144.0

CWIP
 
1,202.9

 
1,385.6

Accumulated Depreciation
 
137.0

 
75.6

Total Transmission Property, Net
 
$
5,875.1

 
$
4,454.0


28



Second Quarter of 2017 Compared to Second Quarter of 2016
 
Reconciliation of Second Quarter of 2016 to Second Quarter of 2017
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Second Quarter of 2016
 
$
94.6

 
 
 
Changes in Transmission Revenues:
 
 
Transmission Revenues
 
85.6

Total Change in Transmission Revenues
 
85.6

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(8.6
)
Depreciation and Amortization
 
(8.2
)
Taxes Other Than Income Taxes
 
(6.6
)
Carrying Costs Expense
 
0.1

Allowance for Equity Funds Used During Construction
 
(0.4
)
Interest Expense
 
(5.5
)
Total Change in Expenses and Other
 
(29.2
)
 
 
 
Income Tax Expense
 
(19.5
)
Equity Earnings
 
(3.2
)
Net Income Attributable to Noncontrolling Interests
 
0.1

 
 
 
Second Quarter of 2017
 
$
128.4


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

Transmission Revenues increased $86 million primarily due to an $84 million increase in formula rates driven by continued investment in transmission assets.

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

Other Operation and Maintenance expenses increased $9 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $8 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $7 million primarily due to increased property taxes as a result of additional transmission investment.
Interest Expense increased $6 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $20 million primarily due to an increase in pretax book income.
Equity Earnings decreased $3 million primarily due to lower earnings at ETT resulting from increased property taxes, depreciation expense, and decreased AFUDC, partially offset by increased revenues. The revenue increase is primarily due to interim rate increases in the third quarter of 2016 and higher loads, partially offset by an ETT settlement rate reduction that went into effect in March 2017.

29



Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016
 
Reconciliation of Six Months Ended June 30, 2016 to Six Months Ended June 30, 2017
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Six Months Ended June 30, 2016
 
$
138.5

 
 
 
Changes in Transmission Revenues:
 
 
Transmission Revenues
 
153.1

Total Change in Transmission Revenues
 
153.1

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(10.9
)
Depreciation and Amortization
 
(17.3
)
Taxes Other Than Income Taxes
 
(13.4
)
Interest and Investment Income
 
0.2

Carrying Costs Expense
 
0.1

Allowance for Equity Funds Used During Construction
 
(2.0
)
Interest Expense
 
(11.0
)
Total Change in Expenses and Other
 
(54.3
)
 
 
 
Income Tax Expense
 
(35.5
)
Equity Earnings
 
(1.5
)
Net Income Attributable to Noncontrolling Interests
 
(0.1
)
 
 
 
Six Months Ended June 30, 2017
 
$
200.2


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

Transmission Revenues increased $153 million primarily due to a $149 million increase in formula rates driven by continued investment in transmission assets.

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

Other Operation and Maintenance expenses increased $11 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $17 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $13 million primarily due to increased property taxes as a result of additional transmission investment.
Interest Expense increased $11 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $36 million primarily due to an increase in pretax book income.


30



GENERATION & MARKETING
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
Generation & Marketing
 
2017
 
2016
 
2017
 
2016
 
 
(in millions)
Revenues
 
$
410.6

 
$
683.8

 
$
1,002.0

 
$
1,431.8

Fuel, Purchased Electricity and Other
 
302.9

 
443.7

 
708.1

 
923.2

Gross Margin
 
107.7

 
240.1

 
293.9

 
508.6

Other Operation and Maintenance
 
68.6

 
100.8

 
154.9

 
194.4

Asset Impairments and Other Related Charges
 
1.9

 

 
13.1

 

Gain on Sale of Merchant Generation Assets
 
0.1

 

 
(226.4
)
 

Depreciation and Amortization
 
5.6

 
50.6

 
11.3

 
99.3

Taxes Other Than Income Taxes
 
3.7

 
10.4

 
5.7

 
20.3

Operating Income
 
27.8

 
78.3

 
335.3

 
194.6

Interest and Investment Income
 
3.0

 

 
5.2

 
0.5

Allowance for Equity Funds Used During Construction
 

 
0.2

 

 
0.4

Interest Expense
 
(4.2
)
 
(8.6
)
 
(10.7
)
 
(17.6
)
Income Before Income Tax Expense
 
26.6

 
69.9

 
329.8

 
177.9

Income Tax Expense
 
0.2

 
20.2

 
117.2

 
57.5

Net Income
 
26.4

 
49.7

 
212.6

 
120.4

Net Income Attributable to Noncontrolling Interests
 

 

 

 

Earnings Attributable to AEP Common Shareholders
 
$
26.4

 
$
49.7

 
$
212.6

 
$
120.4


Summary of MWhs Generated for Generation & Marketing
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
 
(in millions of MWhs)
Fuel Type:
 

 
 

 
 

 
 

Coal
2

 
6

 
8

 
11

Natural Gas

 
3

 
2

 
7

Total MWhs
2

 
9

 
10

 
18



31



Second Quarter of 2017 Compared to Second Quarter of 2016
Reconciliation of Second Quarter of 2016 to Second Quarter of 2017
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
 
 
 
Second Quarter of 2016
 
$
49.7

 
 
 

Changes in Gross Margin:
 
 

Generation
 
(125.3
)
Retail, Trading and Marketing
 
(13.7
)
Other
 
6.6

Total Change in Gross Margin
 
(132.4
)
 
 
 

Changes in Expenses and Other:
 
 

Other Operation and Maintenance
 
32.2

Asset Impairments and Other Related Charges
 
(1.9
)
Gain on Sale of Merchant Generation Assets
 
(0.1
)
Depreciation and Amortization
 
45.0

Taxes Other Than Income Taxes
 
6.7

Interest and Investment Income
 
3.0

Allowance for Equity Funds Used During Construction
 
(0.2
)
Interest Expense
 
4.4

Total Change in Expenses and Other
 
89.1

 
 
 

Income Tax Expense
 
20.0

 
 
 

Second Quarter of 2017
 
$
26.4


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

Generation decreased $125 million primarily due to the reduction of revenues associated with the sale of certain merchant generation assets.
Retail, Trading and Marketing decreased $14 million when compared to the impact of favorable wholesale trading and marketing performance in 2016.
Other