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Section 1: 10-K (10-K)

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
(Mark One)
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the FISCAL YEAR ended December 31, 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
 
Registrant; State of Incorporation;
 
I.R.S. Employer
File Number
 
Address; and Telephone Number
 
Identification No.
 
 
 
 
 
333-21011
 
FIRSTENERGY CORP.
 
34-1843785
 
 
(An Ohio Corporation)
 
 
 
 
76 South Main Street
 
 
 
 
Akron, OH 44308
 
 
 
 
Telephone (800)736-3402
 
 
 
 
 
 
 
000-53742
 
FIRSTENERGY SOLUTIONS CORP.
 
31-1560186
 
 
(An Ohio Corporation)
 
 
 
 
c/o FirstEnergy Corp.
 
 
 
 
76 South Main Street
 
 
 
 
Akron, OH 44308
 
 
 
 
Telephone (800)736-3402
 
 
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Registrant
 
Title of Each Class
 
Name of Each Exchange
on Which Registered
 
 
 
 
 
FirstEnergy Corp.
 
Common Stock, $0.10 par value per share
 
New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Registrant
 
Title of Class
 
 
 
FirstEnergy Solutions Corp.
 
Common Stock, no par value per share
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes þ No o
 
FirstEnergy Corp.
Yes o No þ
 
FirstEnergy Solutions Corp.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o No þ
 
FirstEnergy Corp. and FirstEnergy Solutions Corp.
Indicate by check mark whether the registrant (1) has 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No o
 
FirstEnergy Corp. and FirstEnergy Solutions Corp.
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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 registrant was required to submit and post such files).
Yes þ No o
 
FirstEnergy Corp. and FirstEnergy Solutions Corp.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
þ
 
FirstEnergy Corp.
þ
 
FirstEnergy Solutions Corp.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or 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 þ
FirstEnergy Corp.
 
 
Accelerated Filer o
N/A
 
 
Non-accelerated Filer (Do not check
if a smaller reporting company)
þ
FirstEnergy Solutions Corp.
 
 
Smaller Reporting Company o
N/A
 
 
Emerging Growth Company o
N/A
If an emerging growth company, indicate by check mark if the registrant has 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. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes o No þ
 
FirstEnergy Corp. and FirstEnergy Solutions Corp.
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and ask price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter.
FirstEnergy Corp., $12,919,874,051 as of June 30, 2017; and for FirstEnergy Solutions Corp., none.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date:
 
 
OUTSTANDING
CLASS
 
AS OF JANUARY 31, 2018
FirstEnergy Corp., $0.10 par value
 
475,589,829

FirstEnergy Solutions Corp., no par value
 
7

FirstEnergy Corp. is the sole holder of FirstEnergy Solutions Corp. common stock.
Documents Incorporated By Reference
 
 
PART OF FORM 10-K INTO WHICH
DOCUMENT
 
DOCUMENT IS INCORPORATED
 
 
 
Proxy Statement for 2018 Annual Meeting of Shareholders of FirstEnergy Corp. to be held May 15, 2018
 
Part III
This combined Form 10-K is separately filed by FirstEnergy Corp. and FirstEnergy Solutions Corp. Information contained herein relating to an individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to the other registrant, except that information relating to FirstEnergy Solutions Corp. is also attributable to FirstEnergy Corp.
OMISSION OF CERTAIN INFORMATION
FirstEnergy Solutions Corp. meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10-K.
 





Forward-Looking Statements: Certain of the matters discussed in this Annual Report on Form 10-K are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, including those factors with respect to such Registrants discussed in (a) Item 1A. Risk Factors, (b) Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) other factors discussed herein and in other filings with the SEC by the Registrants. These risks, unless otherwise indicated, are presented on a consolidated basis for FirstEnergy; if and to the extent a deconsolidation occurs with respect to certain FirstEnergy companies the risks described herein may materially change. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Form 10-K. Neither of the Registrants undertake any obligation to update these statements, except as required by law.





TABLE OF CONTENTS
 
Page
 
 
 
 
Part I.
 
 
 
Item 1. Business
 
 
Maryland Regulatory Matters
West Virginia Regulatory Matters
FirstEnergy Website and Other Social Media Sites and Applications
 
 
 
 
 
 
 
 
 
 
Item 4. Mine Safety Disclosures
 
 
 
 
 
 
 
 
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

i




TABLE OF CONTENTS
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 16. Form 10-K Summary


ii




GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:

AE
Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, 2011, which subsequently merged with and into FE on January 1, 2014
AESC
Allegheny Energy Service Corporation, a subsidiary of FirstEnergy Corp.
AE Supply
Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary
AGC
Allegheny Generating Company, a generation subsidiary of AE Supply and equity method investee of MP
ATSI
American Transmission Systems, Incorporated, formerly a direct subsidiary of FE that became a subsidiary of FET in April 2012, which owns and operates transmission facilities
BU Energy
Buchanan Energy Company of Virginia, LLC, a subsidiary of AE Supply, and 50% owner in a joint venture that owns the Buchanan Generating Facility
Buchanan Generation
Buchanan Generation, LLC, a joint venture between AE Supply and CNX Gas Corporation
CEI
The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
CES
Competitive Energy Services, a reportable operating segment of FirstEnergy
FE
FirstEnergy Corp., a public utility holding company
FENOC
FirstEnergy Nuclear Operating Company, a subsidiary of FE, which operates nuclear generating facilities
FES
FirstEnergy Solutions Corp., together with its consolidated subsidiaries, which provides energy-related products and services
FESC
FirstEnergy Service Company, which provides legal, financial and other corporate support services
FET
FirstEnergy Transmission, LLC, formerly known as Allegheny Energy Transmission, LLC, which is the parent of ATSI, MAIT and TrAIL, and has a joint venture in PATH
FEV
FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures
FG
FirstEnergy Generation, LLC, a wholly-owned subsidiary of FES, which owns and operates non-nuclear generating facilities
FirstEnergy
FirstEnergy Corp., together with its consolidated subsidiaries
Global Holding
Global Mining Holding Company, LLC, a joint venture between FEV, WMB Marketing Ventures, LLC and Pinesdale LLC
Global Rail
Global Rail Group, LLC, a subsidiary of Global Holding that owns coal transportation operations near Roundup, Montana
GPU
GPU, Inc., former parent of JCP&L, ME and PN, that merged with FE on November 7, 2001
Green Valley
Green Valley Hydro, LLC, which owned hydroelectric generating stations
JCP&L
Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
MAIT
Mid-Atlantic Interstate Transmission, LLC, a subsidiary of FET, which owns and operates transmission facilities
ME
Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MP
Monongahela Power Company, a West Virginia electric utility operating subsidiary
NG
FirstEnergy Nuclear Generation, LLC, a subsidiary of FES, which owns nuclear generating facilities
OE
Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies
CEI, OE and TE
PATH
Potomac-Appalachian Transmission Highline, LLC, a joint venture between FE and a subsidiary of AEP
PATH-Allegheny
PATH Allegheny Transmission Company, LLC
PATH-WV
PATH West Virginia Transmission Company, LLC
PE
The Potomac Edison Company, a Maryland and West Virginia electric utility operating subsidiary
Penn
Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies
ME, PN, Penn and WP
PN
Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Signal Peak
Signal Peak Energy, LLC, an indirect subsidiary of Global Holding that owns mining operations near Roundup, Montana
TE
The Toledo Edison Company, an Ohio electric utility operating subsidiary
TrAIL
Trans-Allegheny Interstate Line Company, a subsidiary of FET, which owns and operates transmission facilities
Utilities
OE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE and WP
WP
West Penn Power Company, a Pennsylvania electric utility operating subsidiary
 
 
The following abbreviations and acronyms are used to identify frequently used terms in this report:
AAA
American Arbitration Association
ADIT
Accumulated Deferred Income Taxes

iii




GLOSSARY OF TERMS, Continued

AEP
American Electric Power Company, Inc.
AFS
Available-for-sale
AFUDC
Allowance for Funds Used During Construction
ALJ
Administrative Law Judge
AMT
Alternative Minimum Tax
AOCI
Accumulated Other Comprehensive Income
ARO
Asset Retirement Obligation
ASU
Accounting Standards Update
Bath County
Bath County Pumped Storage Hydro-Power Station
BGS
Basic Generation Service
bps
Basis points
BNSF
BNSF Railway Company
BRA
PJM RPM Base Residual Auction
CAA
Clean Air Act
CBA
Collective Bargaining Agreement
CCR
Coal Combustion Residuals
CERCLA
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
CFL
Compact Fluorescent Light
CFR
Code of Federal Regulations
CFTC
Commodity Futures Trading Commission
CO2
Carbon Dioxide
CPP
EPA's Clean Power Plan
CSAPR
Cross-State Air Pollution Rule
CSX
CSX Transportation, Inc.
CTA
Consolidated Tax Adjustment
CWA
Clean Water Act
D.C. Circuit
United States Court of Appeals for the District of Columbia Circuit
DCPD
Deferred Compensation Plan for Outside Directors
DCR
Delivery Capital Recovery
DMR
Distribution Modernization Rider
DOE
United States Department of Energy
DPM
Distribution Platform Modernization
DR
Demand Response
DSIC
Distribution System Improvement Charge
DSP
Default Service Plan
DTA
Deferred Tax Asset
EDC
Electric Distribution Company
EDCP
Executive Deferred Compensation Plan
EE&C
Energy Efficiency and Conservation
EGS
Electric Generation Supplier
EGU
Electric Generation Units
ELPC
Environmental Law & Policy Center
EmPOWER Maryland
EmPOWER Maryland Energy Efficiency Act
ENEC
Expanded Net Energy Cost
EPA
United States Environmental Protection Agency
EPRI
Electric Power Research Institute
ERO
Electric Reliability Organization
ESOP
Employee Stock Ownership Plan
ESP
Electric Security Plan
ESP IV
Electric Security Plan IV
ESP IV PPA
Unit Power Agreement entered into on April 1, 2016, by and between the Ohio Companies and FES
Facebook®
Facebook is a registered trademark of Facebook, Inc.

iv




GLOSSARY OF TERMS, Continued

FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
Fitch
Fitch Ratings
FMB
First Mortgage Bond
FPA
Federal Power Act
FTR
Financial Transmission Right
GAAP
Accounting Principles Generally Accepted in the United States of America
GHG
Greenhouse Gases
HCl
Hydrochloric Acid
IBEW
International Brotherhood of Electrical Workers
ICE
Intercontinental Exchange, Inc.
ICP 2007
FirstEnergy Corp. 2007 Incentive Plan
ICP 2015
FirstEnergy Corp. 2015 Incentive Compensation Plan
IIP
Investment Infrastructure Program
IRP
Integrated Resource Plan
IRS
Internal Revenue Service
ISO
Independent System Operator
kV
Kilovolt
kW
Kilowatt
KWH
Kilowatt-hour
LBR
Little Blue Run
LED
Light Emitting Diode
LOC
Letter of Credit
LSE
Load Serving Entity
LS Power
LS Power Equity Partners, LP
LTIIPs
Long-Term Infrastructure Improvement Plans
MATS
Mercury and Air Toxics Standards
MDPSC
Maryland Public Service Commission
MISO
Midcontinent Independent System Operator, Inc.
MLP
Master Limited Partnership
mmBTU
One Million British Thermal Units
Moody’s
Moody’s Investors Service, Inc.
MOPR
Minimum Offer Price Rule
MVP
Multi-Value Project
MW
Megawatt
MWH
Megawatt-hour
NAAQS
National Ambient Air Quality Standards
NDT
Nuclear Decommissioning Trust
NEIL
Nuclear Electric Insurance Limited
NERC
North American Electric Reliability Corporation
NJAPA
New Jersey Administrative Procedure Act
NJBPU
New Jersey Board of Public Utilities
NOL
Net Operating Loss
NOPR
Notice of Proposed Rulemaking
NOV
Notice of Violation
NOx
Nitrogen Oxide
NPDES
National Pollutant Discharge Elimination System
NRC
Nuclear Regulatory Commission
NS
Norfolk Southern Corporation
NSR
New Source Review
NUG
Non-Utility Generation
NYPSC
New York State Public Service Commission

v




GLOSSARY OF TERMS, Continued

OCA
Office of Consumer Advocate
OCC
Ohio Consumers' Counsel
OPEB
Other Post-Employment Benefits
OPEIU
Office and Professional Employees International Union
ORC
Ohio Revised Code
OTC
Over The Counter
OTTI
Other-Than-Temporary Impairments
OVEC
Ohio Valley Electric Corporation
PA DEP
Pennsylvania Department of Environmental Protection
PCB
Polychlorinated Biphenyl
PCRB
Pollution Control Revenue Bond
PJM
PJM Interconnection, L.L.C.
PJM Region
The aggregate of the zones within PJM
PJM Tariff
PJM Open Access Transmission Tariff
PM
Particulate Matter
POLR
Provider of Last Resort
POR
Purchase of Receivables
PPA
Purchase Power Agreement
PPB
Parts per Billion
PPUC
Pennsylvania Public Utility Commission
PSA
Power Supply Agreement
PSD
Prevention of Significant Deterioration
PUCO
Public Utilities Commission of Ohio
PURPA
Public Utility Regulatory Policies Act of 1978
R&D
Research and Development
RCRA
Resource Conservation and Recovery Act
REC
Renewable Energy Credit
Regulation FD
Regulation Fair Disclosure promulgated by the SEC
REIT
Real Estate Investment Trust
RFC
ReliabilityFirst Corporation
RFP
Request for Proposal
RGGI
Regional Greenhouse Gas Initiative
ROE
Return on Equity
RPM
Reliability Pricing Model
RRS
Retail Rate Stability
RSS
Rich Site Summary
RTEP
Regional Transmission Expansion Plan
RTO
Regional Transmission Organization
RWG
Restructuring Working Group
S&P
Standard & Poor’s Ratings Service
SB310
Substitute Senate Bill No. 310
SBC
Societal Benefits Charge
SEC
United States Securities and Exchange Commission
Seventh Circuit
United States Court of Appeals for the Seventh Circuit
SIP
State Implementation Plan(s) Under the Clean Air Act
Sixth Circuit
United States Court of Appeals for the Sixth Circuit
SO2
Sulfur Dioxide
SOS
Standard Offer Service
SPE
Special Purpose Entity
SRC
Storm Recovery Charge
SREC
Solar Renewable Energy Credit
SSA
Social Security Administration

vi




GLOSSARY OF TERMS, Continued

SSO
Standard Service Offer
Tax Act
Tax Cuts and Jobs Act adopted December 22, 2017
TDS
Total Dissolved Solid
TMI-2
Three Mile Island Unit 2
TO
Transmission Owner
Twitter®
Twitter is a registered trademark of Twitter, Inc.
UWUA
Utility Workers Union of America
VEPCO
Virginia Electric and Power Company
VIE
Variable Interest Entity
VMP
Vegetation Management Plan
VMS
Vegetation Management Surcharge
VSCC
Virginia State Corporation Commission
WVDEP
West Virginia Department of Environmental Protection
WVPSC
Public Service Commission of West Virginia
 

vii




PART I
ITEM 1.
BUSINESS
The Companies

FE was incorporated under Ohio law in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding equity of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, FES and its principal subsidiaries (FG and NG), AE Supply, MP, PE, WP, FET and its principal subsidiaries (ATSI, MAIT and TrAIL), and AESC. In addition, FE holds all of the outstanding equity of other direct subsidiaries including: FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., GPU Nuclear, Inc. and Allegheny Ventures, Inc.

FE and its subsidiaries are principally involved in the generation, transmission and distribution of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over six million customers in the Midwest and Mid-Atlantic regions. Its regulated and unregulated generation subsidiaries control over 16,000 MWs of capacity from a diverse mix of non-emitting nuclear, scrubbed coal, natural gas, hydroelectric and other renewables. FirstEnergy’s transmission operations include approximately 24,500 miles of lines and two regional transmission operation centers.
FirstEnergy’s revenues are primarily derived from the sale of energy and related products and services by its unregulated competitive subsidiaries (FES and AE Supply), and electric service provided by its utility operating subsidiaries (OE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE and WP) and its transmission subsidiaries (ATSI, MAIT and TrAIL).

Unregulated Competitive Subsidiaries

FES, a subsidiary of FE, was incorporated under Ohio law in 1997. FES provides energy-related products and services to retail and wholesale customers. FES also owns and operates, through its FG subsidiary, fossil generating facilities and owns, through its NG subsidiary, nuclear generating facilities, which are operated by FENOC. FG, a subsidiary of FES, was organized under Ohio law in 2000. FG sells the entire output of its fossil generating facilities (5,440 MWs) to FES. NG was organized under Ohio law in 2005. NG sells the entire output of its nuclear generating facilities (4,048 MWs) to FES. NG's nuclear generating facilities are operated and maintained by FENOC, a separate subsidiary of FE, organized under Ohio law in 1998.

AE Supply was organized under Delaware law in 1999. AE Supply provides energy-related products and services primarily to wholesale customers. AE Supply also owns and operates the Pleasants generating facility (1,300 MWs), and owns approximately 59% of AGC and a 50% interest in the Buchanan Generating facility.

AGC was organized under Virginia law in 1981. Approximately 59% of AGC is owned by AE Supply and approximately 41% is owned by MP. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility (1,200 MWs) and its connecting transmission facilities. AGC provides the generation capacity from this facility to AE Supply and MP.

AE Supply and AGC entered into an asset purchase agreement with a subsidiary of LS Power, as amended and restated in August 2017, to sell four natural gas generating plants, AE Supply's interest in the Buchanan Generating facility and approximately 59% of AGC’s interest in Bath County (1,615 MWs of combined capacity) for an all-cash purchase price of $825 million, subject to adjustments. On December 13, 2017, AE Supply completed the sale of its four natural gas generating plants and expects to complete the sale of approximately 59% of AGC’s interest in the Bath County hydroelectric power station and BU Energy’s 50% interest in the Buchanan Generating facility in the first half of 2018. For additional information, see "Competitive Generation Asset Sale" below.

FES, FG, NG, AE Supply and AGC comply with the regulations, orders, policies and practices prescribed by the SEC, FERC, and applicable state regulatory authorities. In addition, NG and FENOC comply with the regulations, orders, policies and practices prescribed by the NRC.

Utility Operating Subsidiaries

The Utilities’ combined service areas encompass approximately 65,000 square miles in Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York. The areas they serve have a combined population of approximately 13.3 million.

OE was organized under Ohio law in 1930 and owns property and does business as an electric public utility in that state. OE engages in the distribution and sale of electric energy to communities in a 7,000 square mile area of central and northeastern Ohio. The area it serves has a population of approximately 2.3 million.

OE owns all of Penn’s outstanding common stock. Penn was organized under Pennsylvania law in 1930 and owns property and does business as an electric public utility in that state. Penn is also authorized to do business in Ohio. Penn furnishes electric service to communities in 1,100 square miles of western Pennsylvania. The area it serves has a population of approximately 0.4 million.


1




CEI was organized under Ohio law in 1892 and does business as an electric public utility in that state. CEI engages in the distribution and sale of electric energy in an area of 1,600 square miles in northeastern Ohio. The area it serves has a population of approximately 1.6 million.

TE was organized under Ohio law in 1901 and does business as an electric public utility in that state. TE engages in the distribution and sale of electric energy in an area of 2,300 square miles in northwestern Ohio. The area it serves has a population of approximately 0.7 million.

JCP&L was organized under New Jersey law in 1925 and owns property and does business as an electric public utility in that state. JCP&L provides transmission and distribution services in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.7 million. JCP&L also has a 50% ownership interest (210 MWs) in a hydroelectric generating facility.

ME was organized under Pennsylvania law in 1917 and owns property and does business as an electric public utility in that state. ME provides distribution services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million. Additionally, as discussed in "FERC Matters" below, ME transferred its transmission assets to MAIT on January 31, 2017.

PN was organized under Pennsylvania law in 1919 and owns property and does business as an electric public utility in that state. PN provides distribution services in 17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million. PN, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, also serves customers in the Waverly, New York vicinity. Additionally, as discussed in "FERC Matters" below, PN transferred its transmission assets to MAIT on January 31, 2017.

PE was organized under Maryland law in 1923 and under Virginia law in 1974. PE is authorized to do business in Virginia, West Virginia and Maryland. PE owns property and does business as an electric public utility in those states. PE provides transmission and distribution services in portions of Maryland and West Virginia and provides transmission services in Virginia in an area totaling approximately 5,500 square miles. The area it serves has a population of approximately 0.9 million.

MP was organized under Ohio law in 1924 and owns property and does business as an electric public utility in the state of West Virginia. MP provides generation, transmission and distribution services in 13,000 square miles of northern West Virginia. The area it serves has a population of approximately 0.8 million. As of December 31, 2017, MP owned or contractually controlled 3,580 MWs of generation capacity that is supplied to its electric utility business. In addition, MP is contractually obligated to provide power to PE to meet its load obligations in West Virginia.

WP was organized under Pennsylvania law in 1916 and owns property and does business as an electric public utility in that state. WP provides transmission and distribution services in 10,400 square miles of southwestern, south-central and northern Pennsylvania. The area it serves has a population of approximately 1.5 million.

The Utilities comply with the regulations, orders, policies and practices prescribed by the SEC, FERC, NERC, and their respective state regulatory authorities (PUCO, PPUC, NJBPU, WVPSC, MDPSC, NYPSC, and VSCC).

Transmission Subsidiaries

ATSI was organized under Ohio law in 1998. ATSI owns major, high-voltage transmission facilities, which consist of approximately 7,800 circuit miles of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV in the PJM Region.

TrAIL was organized under Maryland law and Virginia law in 2006. TrAIL was formed to finance, construct, own, operate and maintain high-voltage transmission facilities in the PJM Region and has several transmission facilities in operation, including a 500 kV transmission line extending approximately 150 miles from southwestern Pennsylvania through West Virginia to a point of interconnection with VEPCO in northern Virginia. TrAIL plans, operates and maintains its transmission system and facilities in accordance with NERC reliability standards, and other applicable regulatory requirements. In addition, TrAIL complies with the regulations, orders, policies and practices prescribed by the SEC, FERC, and applicable state regulatory authorities.

MAIT was organized under Delaware law in 2015. As discussed in "FERC Matters" below, ME and PN transferred their transmission facilities to MAIT on January 31, 2017. The assets transferred consist of approximately 4,234 circuit miles of transmission lines with nominal voltages of 500 kV, 345 kV, 230 kV, 138 kV, 115 kV, 69 kV and 46 kV in the PJM Region.

Each of ATSI, MAIT and TrAIL plans, operates, and maintains its transmission system in accordance with NERC reliability standards, and other applicable regulatory requirements. In addition, each of ATSI, MAIT and TrAIL complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and applicable state regulatory authorities.


2




Service Company

FESC provides legal, financial and other corporate support services at cost, in accordance with its cost allocation manual, to affiliated FirstEnergy companies.

Operating Segments

FirstEnergy's reportable operating segments are as follows: Regulated Distribution, Regulated Transmission and CES.

The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment's results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs.

The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, MAIT (effective January 31, 2017) and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP). The segment's revenues are primarily derived from forward-looking rates at ATSI and TrAIL, as well as stated transmission rates at certain of FirstEnergy's utilities. As discussed in "Utility Regulation - FERC Matters," below, MAIT and JCP&L submitted applications to FERC requesting authorization to implement forward-looking formula transmission rates. In March 2017, FERC approved JCP&L's and MAIT's forward-looking formula rates, subject to refund, with effective dates of June 1, 2017, and July 1, 2017, respectively. Additionally, MAIT and JCP&L filed settlement agreements with FERC on October 13, 2017 and December 21, 2017, respectively, both pending final orders by FERC. Both the forward-looking and stated rates recover costs and provide a return on transmission capital investment. Under forward-looking rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which are subject to an annual true-up based on actual costs. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities.

The CES segment, through FES and AE Supply, primarily supplies electricity to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including the Utilities. As of January 31, 2018, this business segment controlled 12,303 MWs of electric generating capacity, including, as discussed in "Unregulated Competitive Subsidiaries" above, 756 MWs of generating capacity which remain subject to an asset purchase agreement with a subsidiary of LS Power that is expected to close in the first half of 2018. The CES segment’s operating results are primarily derived from electric generation sales less the related costs of electricity generation, including fuel, purchased power and net transmission (including congestion) and ancillary costs and capacity costs charged by PJM to deliver energy to the segment’s customers, as well as other operating and maintenance costs, including costs incurred by FENOC.

Interest expense on stand-alone holding company debt, corporate income taxes and other businesses that do not constitute an operating segment are categorized as Corporate/Other for reportable business segment purposes. Additionally, reconciling adjustments for the elimination of inter-segment transactions are included in Corporate/Other. As of December 31, 2017, Corporate/Other had $6.8 billion of stand-alone holding company long-term debt, of which $1.45 billion was subject to variable-interest rates, and $300 million was borrowed by FE under its revolving credit facility. On January 22, 2018, FE repaid its $1.45 billion of outstanding variable-interest rate debt using the proceeds from the $2.5 billion equity investment.

Additional information regarding FirstEnergy’s reportable segments is provided in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," and Note 19, "Segment Information," of the Combined Notes to Consolidated Financial Statements. FES does not have separate reportable operating segments.

Competitive Generation

As of January 31, 2018, FirstEnergy’s competitive generating portfolio consists of 12,303 MWs of electric generating capacity. Of the competitive generation asset portfolio, approximately 6,136 MWs (49.9%) consist of coal-fired capacity; 4,048 MWs (32.9%) consist of nuclear capacity; 713 MWs (5.8%) consist of hydroelectric capacity; 733 MWs (6.0%) consist of oil and natural gas units; 496 MWs (4.0%) consist of wind and solar power arrangements; and 177 MWs (1.4%) consist of capacity entitlements to output from generation assets owned by OVEC. All units are located within PJM and sell electric energy, capacity and other products into the wholesale markets that are operated by PJM. Within CES' generation portfolio, 10,180 MWs consist of FES' facilities that are operated by FENOC and FG (including entitlements from OVEC, wind and solar power arrangements), and except for portions of Bruce Mansfield facilities that are subject to the sale and leaseback arrangements with non-affiliates for which the corresponding output of these arrangements is available to FES through power sales agreements, are all owned directly by NG and FG. Another 2,123 MWs of the CES' portfolio consists of AE Supply's facilities, including AE Supply's entitlement to 713 MWs from AGC's interest in Bath County and 67 MWs of AE Supply's 3.01% entitlement from OVEC's generation output. As discussed below, AE Supply and AGC agreed to sell to a subsidiary of LS Power 1,615 MWs of electric generating capacity. On December 13, 2017, AE Supply completed the sale of its four natural gas generating plants (859 MWs). The sale of the remaining 756 MWs of generating capacity

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is expected to close in the first half of 2018. FES' generating facilities are concentrated primarily in Ohio and Pennsylvania and AE Supply's generating facilities are primarily located in West Virginia, Virginia and Ohio.

On January 10, 2018, a fire damaged the scrubber, stack and other plant property and systems associated with Bruce Mansfield Units 1 and 2. Evaluation of the extent of the damage, which may be significant, to the scrubber, stack and other plant property and systems associated with Units 1 and 2 is underway and is expected to take several weeks. Unit 3, which had been off-line for maintenance, was unaffected by the fire. The affected plant property and systems are insured and management is working with the insurance carriers to complete the assessment. At this time management is unable to estimate the financial effect of the fire on Units 1 and 2.

In November 2016, FirstEnergy announced a strategic review to exit its commodity-exposed generation at CES, which is primarily comprised of the operations of FES and AE Supply. In connection with this strategic review, AE Supply and AGC entered into an asset purchase agreement with a subsidiary of LS Power, as amended and restated in August 2017, to sell four natural gas generating plants, AE Supply's interest in the Buchanan Generating facility and approximately 59% of AGC’s interest in Bath County (1,615 MWs of combined capacity) for an all-cash purchase price of $825 million, subject to adjustments and through multiple, independent closings. On December 13, 2017, AE Supply completed the sale of the natural gas generating plants with net proceeds, subject to post-closing adjustments, of approximately $388 million. The sale of AE Supply’s interests in the Bath County hydroelectric power station and the Buchanan Generating facility is expected to generate net proceeds of $375 million and is anticipated to close in the first half of 2018, subject in each case to various customary and other closing conditions, including, without limitation, receipt of regulatory approvals.

Additionally, on March 6, 2017, AE Supply and MP entered into an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station (1,300 MWs) for approximately $195 million, resulting from an RFP issued by MP to address its generation shortfall. On January 12, 2018, FERC issued an order denying authorization for the transaction, holding that MP and AE Supply did not demonstrate the sale was consistent with the public interest and the transaction did not fall within the safe harbors for meeting FERC’s affiliate cross-subsidization analysis. On January 26, 2018, the WVPSC approved the transfer of the Pleasants Power Station, subject to certain conditions as further described in "West Virginia Regulatory Matters," below, which included MP assuming significant commodity risk. Based on the FERC ruling and the conditions included in the WVPSC order, MP and AE Supply terminated the asset purchase agreement and on February 16, 2018, AE Supply announced its intent to exit operations of the Pleasants Power Station by January 1, 2019, through either sale or deactivation, which resulted in a pre-tax impairment charge of $120 million.

With the sale of the gas plants completed, upon the consummation of the sale of AGC's interest in the Bath County hydroelectric power station or the sale or deactivation of the Pleasants Power Station, AE Supply is obligated under the amended and restated purchase agreement and AE Supply's applicable debt agreements, to satisfy and discharge approximately $305 million of currently outstanding senior notes as well as its $142 million of pollution control notes and AGC’s $100 million senior notes, which are expected to require the payment of “make-whole” premiums currently estimated to be approximately $95 million based on current interest rates. For additional information see "Outlook" below.

The strategic options to exit the remaining portion of the CES portfolio, which is primarily at FES, are limited. The credit quality of FES, including its unsecured debt rating of Ca at Moody’s, C at S&P, and C at Fitch and the negative outlook from Moody’s and S&P, has challenged its ability to consummate asset sales. Furthermore, the inability to obtain legislative support under the Department of Energy’s recent NOPR, which was rejected by FERC, limits FES’ strategic options to plant deactivations, restructuring its debt and other financial obligations with its creditors, and/or to seek protection under U.S. bankruptcy laws.
 
As part of the strategic review, FES evaluated its options with respect to its nuclear power plants. Factors considered as part of this review included current and forecasted market conditions, such as wholesale power and capacity prices, legislative and regulatory solutions that recognize their environmental and energy security benefits, and many other factors, including the significant capital and operating costs associated with operating a safe and reliable nuclear fleet. Based on this analysis, given the weak power and capacity price environment and the lack of legislative and regulatory solutions achieved to date, FES concluded that it would be increasingly difficult to operate these facilities in this environment and absent significant change concluded that it was probable that the facilities would be either deactivated or sold before the end of their estimated useful lives. As a result, FES recorded a pre-tax charge of $2.0 billion in the fourth quarter of 2017 to fully impair the nuclear facilities, including the generating plants and nuclear fuel as well as to reserve against the value of materials and supplies inventory and to increase its asset retirement obligation. For additional information see Note 2, "Asset Sales and Impairments."
 
Although FES has access to a $500 million secured line of credit with FE, all of which was available as of January 31, 2018, its current credit rating and the current forward wholesale pricing environment present significant challenges to FES. As previously disclosed, FES has $515 million of maturing debt in 2018 (excluding intra-company debt), beginning with a $100 million principal payment due April 2, 2018. Based on FES' current senior unsecured debt rating, capital structure and long-term cash flow projections, the debt maturities are unlikely to be refinanced. Although management continues to explore cost reductions and other options to improve cash flow, these obligations and their impact to liquidity raise substantial doubt about FES’ ability to meet its obligations as they come due over the next twelve months and, as such, its ability to continue as a going concern.


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Regulated Generation

As of January 31, 2018, FirstEnergy’s regulated generating portfolio consists of 3,790 MWs of diversified capacity contained within the Regulated Distribution segment: 210 MWs consist of JCP&L's 50% ownership interest in the Yard's Creek hydroelectric facility in New Jersey; and 3,580 MWs consist of MP's facilities, including 487 MWs from AGC's interest in Bath County that MP partially owns and 11 MWs of MP's 0.49% entitlement from OVEC's generation output. MP's facilities are concentrated primarily in West Virginia. On December 16, 2016, MP issued an RFP to address its generation shortfall previously identified in the IRP filed with the WVPSC. The IRP identified a capacity shortfall for MP starting in 2016 and exceeding 700 MWs by 2020 and 850 MWs by 2027. AE Supply was the winning bidder of the RFP to address MP’s generation shortfall and on March 6, 2017, MP and AE Supply signed an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station (1,300 MW). As discussed in "Competitive Generation," above, based on the FERC ruling and the conditions included in the WVPSC order, MP and AE Supply terminated the asset purchase agreement.
Utility Regulation
State Regulation

Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.

As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates. In addition, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility.

Following the adoption of the Tax Act, various state regulatory proceedings have been initiated to investigate the impact of the Tax Act on the Utilities’ rates and charges. State proceedings which have arisen are discussed below. The Utilities continue to monitor and investigate the impact of state regulatory impacts resulting from the Tax Act.
Federal Regulation

With respect to their wholesale services and rates, the Utilities, AE Supply, ATSI, AGC, FES, FG, MAIT, NG and TrAIL are subject to regulation by FERC. Under the FPA, FERC regulates rates for interstate wholesale sales, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. FERC regulations require ATSI, JCP&L, MAIT, MP, PE, WP and TrAIL to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of ATSI, JCP&L, MAIT, MP, PE, WP and TrAIL are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff. See "FERC Matters" below.

To date, FERC has yet to issue guidance to address how to reflect the impacts resulting from the Tax Act in customer rates. Management continues to monitor and investigate the impact of changes to federal regulation resulting from the Tax Act.

FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Utilities, AE Supply, FES and certain of its subsidiaries, Buchanan Generation and Green Valley each have been authorized by FERC to sell wholesale power in interstate commerce at market-based rates and have a market-based rate tariff on file with FERC, although major wholesale purchases remain subject to regulation by the relevant state commissions. As a condition to selling electricity on a wholesale basis at market-based rates, the Utilities, AE Supply, FES and certain of its subsidiaries, Buchanan Generation and Green Valley, like other entities granted market-based rate authority, must file electronic quarterly reports with FERC listing their sales transactions for the prior quarter. However, consistent with its historical practice, FERC has granted AE Supply, FES and certain of its subsidiaries, Buchanan Generation and Green Valley a waiver from certain reporting, record-keeping and accounting requirements that typically apply to traditional public utilities. Along with market-based rate authority, FERC also granted AE Supply, FES and certain of its subsidiaries, Buchanan Generation and Green Valley blanket authority to issue securities and assume liabilities under Section 204 of the FPA.

The nuclear generating facilities owned and leased by NG and operated by FENOC are subject to extensive regulation by the NRC. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security, environmental and radiological aspects of those stations. The NRC may modify, suspend or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of the licenses. FENOC is the licensee for the operating nuclear plants and has direct compliance responsibility for NRC matters. FES controls the economic dispatch of NG’s plants. See "Nuclear Regulation" below.


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Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES and certain of its subsidiaries, AE Supply, FENOC, ATSI, MAIT and TrAIL. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.

FirstEnergy, including FES, believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy, including FES, occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy, including FES, develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy's, including FES, part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, and obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations and cash flows.
Regulatory Accounting

FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities, AGC, ATSI, MAIT and TrAIL since their rates are established by a third-party regulator with the authority to set rates that bind customers, are cost-based and can be charged to and collected from customers.

The Utilities, AGC, ATSI, MAIT and TrAIL recognize, as regulatory assets and regulatory liabilities, costs which FERC and the various state utility commissions, as applicable, have authorized for recovery/return from/to customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets and regulatory liabilities would have been charged to income as incurred. All regulatory assets and liabilities are expected to be recovered/returned from/to customers. Based on current ratemaking procedures, the Utilities, AGC, ATSI, MAIT and TrAIL continue to collect cost-based rates for their transmission and distribution services; accordingly, it is appropriate that the Utilities, AGC, ATSI, MAIT and TrAIL continue the application of regulatory accounting to those operations. Regulatory accounting is applied only to the parts of the business that meet the above criteria. If a portion of the business applying regulatory accounting no longer meets those requirements, previously recorded net regulatory assets or liabilities are removed from the balance sheet in accordance with GAAP.

As a result of the Tax Act, FirstEnergy adjusted its net deferred tax liabilities at December 31, 2017, for the reduction in the corporate income tax rate from 35% to 21%. For the portions of FirstEnergy’s business that apply regulatory accounting, the impact of reducing the net deferred tax liabilities was offset with a regulatory liability, as appropriate, for amounts expected to be refunded to rate payers in future rates, with the remainder recorded to deferred income tax expense.
Maryland Regulatory Matters

PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.

The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption and demand and requiring each electric utility to file a plan every three years. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond, beginning with the goal of 0.97% savings achieved under PE's current plan for 2016, and increasing 0.2% per year thereafter to reach 2%. The Maryland legislature in April 2017 adopted a statute requiring the same 0.2% per year increase, up to the ultimate goal of 2% annual savings, for the duration of the 2018-2020 and 2021-2023 EmPOWER Maryland program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. The costs of PE's 2015-2017 plan approved by the MDPSC in December 2014 were approximately $60 million. PE filed its 2018-2020 EmPOWER Maryland plan on August 31, 2017. The 2018-2020 plan continues and expands upon prior years' programs, and adds new programs, for a projected total cost of $116 million over the three-year period. On December 22, 2017, the MDPSC issued an order approving the 2018-2020 plan with various modifications. PE recovers program costs subject to a five-year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE.

On February 27, 2013, the MDPSC issued an order requiring the Maryland electric utilities to submit analyses relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations. PE's responsive filings discussed the steps needed to harden the utility's system in order to attempt to achieve various levels of storm response speed described in the February 2013 Order, and projected that it would require approximately $2.7 billion in infrastructure investments over 15 years to attempt to achieve the quickest level of response for the largest storm projected in the February 2013 Order. On July 1, 2014, the Staff of the MDPSC issued a set of reports that recommended the imposition of extensive additional

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requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting, as well as the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staff of the MDPSC proposed that the Maryland utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost. The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not issued a ruling on any of those matters.

On September 26, 2016, the MDPSC initiated a new proceeding to consider an array of issues relating to electric distribution system design, including matters relating to electric vehicles, distributed energy resources, advanced metering infrastructure, energy storage, system planning, rate design, and impacts on low-income customers. Comments were filed and a hearing was held in late 2016. On January 31, 2017, the MDPSC issued a notice establishing five working groups to address these issues over the following eighteen months, and also directed the retention of an outside consultant to prepare a report on costs and benefits of distributed solar generation in Maryland. On January 19, 2018, PE filed a joint petition, along with other utility companies, work group stakeholders, and the MDPSC electric vehicle work group leader, to implement a statewide electric vehicle portfolio. If approved, PE will launch an electric vehicle charging infrastructure program on January 1, 2019, offering up to 2,000 rebates for electric vehicle charging equipment to residential customers, and deploying up to 259 chargers at non-residential customer service locations at a projected total cost of $12 million. PE is proposing to recover program costs subject to a five-year amortization. On February 6, 2018, the MDPSC opened a new proceeding to consider the petition and directed that comments be filed by March 16, 2018.

On January 12, 2018, the MDPSC instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of Maryland utilities. PE must track and apply regulatory accounting treatment for the impacts beginning January 1, 2018, and submitted a report to the MDPSC on February 15, 2018, estimating that the Tax Act impacts would be approximately $7 million to $8 million annually for PE’s customers and proposed to file a base rate case in the third quarter of 2018 where the benefits from the effects of the Tax Act will be realized by customers through a lower rate increase than would otherwise be necessary.
New Jersey Regulatory Matters

JCP&L currently provides BGS for retail customers who do not choose a third party EGS and for customers of third-party EGSs that fail to provide the contracted service. The supply for BGS is comprised of two components, procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component reflects hourly real time energy prices and is available for larger commercial and industrial customers. The second BGS component provides a fixed price service and is intended for smaller commercial and residential customers. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.

JCP&L currently operates under rates that were approved by the NJBPU on December 12, 2016, effective as of January 1, 2017. These rates provide an annual increase in operating revenues of approximately $80 million from those previously in place and are intended to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating for other business and operating expenses. In addition, on January 25, 2017, the NJBPU approved the acceleration of the amortization of JCP&L’s 2012 major storm expenses that are recovered through the SRC in order for JCP&L to achieve full recovery by December 31, 2019.

Pursuant to the NJBPU's March 26, 2015 final order in JCP&L's 2012 rate case proceeding directing that certain studies be completed, on July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such studies, which included operational and financial components. The independent consultant conducting the review issued a final report on July 27, 2016, recognizing that JCP&L is meeting the NJBPU requirements and making various operational and financial recommendations. The NJBPU issued an Order on August 24, 2016, that accepted the independent consultant’s final report and directed JCP&L, the Division of Rate Counsel and other interested parties to address the recommendations.

In an Order issued October 22, 2014, in a generic proceeding to review its policies with respect to the use of a CTA in base rate cases, the NJBPU stated that it would continue to apply its current CTA policy in base rate cases, subject to incorporating the following modifications: (i) calculating savings using a five-year look back from the beginning of the test year; (ii) allocating savings with 75% retained by the company and 25% allocated to rate payers; and (iii) excluding transmission assets of electric distribution companies in the savings calculation. On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order regarding the generic CTA proceeding to the Superior Court of New Jersey Appellate Division and JCP&L filed to participate as a respondent in that proceeding supporting the order. On September 18, 2017, the Superior Court of New Jersey Appellate Division reversed the NJBPU's Order on the basis that the NJBPU's modification of its CTA methodology did not comply with the procedures of the NJAPA. JCP&L's existing rates are not expected to be impacted by this order. On December 19, 2017, the NJBPU approved the issuance of proposed rules to modify the CTA methodology consistent with its October 22, 2014 Generic Order. The proposed rule was published in the NJ Register on January 16, 2018, and was republished on February 6, 2018, to correct an error. Interested parties have sixty days to comment on the proposed rulemaking.

At the December 19, 2017 NJBPU public meeting, the NJBPU approved its IIP rulemaking. The IIP creates a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing components that enhance reliability, resiliency, and/or safety. JCP&L expects to make a filing in 2018.


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On January 31, 2018, the NJBPU instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of New Jersey utilities. JCP&L must track and apply regulatory accounting treatment for the impacts effective January 1, 2018, and file a petition with the NJBPU by March 2, 2018, regarding the expected impacts of the Tax Act on JCP&L’s expenses and revenues and how the effects will be passed through to its customers.
Ohio Regulatory Matters

The Ohio Companies currently operate under ESP IV which commenced June 1, 2016 and expires May 31, 2024. The material terms of ESP IV, as approved in the PUCO’s Opinion and Order issued on March 31, 2016 and Fifth Entry on Rehearing on October 12, 2016, include Rider DMR, which provides for the Ohio Companies to collect $132.5 million annually for three years, with the possibility of a two-year extension. Rider DMR will be grossed up for federal income taxes, resulting in an approved amount of approximately $204 million annually. Revenues from Rider DMR will be excluded from the significantly excessive earnings test for the initial three-year term but the exclusion will be reconsidered upon application for a potential two-year extension. The PUCO set three conditions for continued recovery under Rider DMR: (1) retention of the corporate headquarters and nexus of operations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO. ESP IV also continues a base distribution rate freeze through May 31, 2024. In addition, ESP IV continues the supply of power to non-shopping customers at a market-based price set through an auction process.

ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $30 million per year from June 1, 2016 through May 31, 2019; $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. Other material terms of ESP IV include: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (2) an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016, and remains pending); (3) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio; and (5) an agreement to file an application to transition to a straight fixed variable cost recovery mechanism for residential customers' base distribution rates (which filing was made on April 3, 2017, and remains pending).

Several parties, including the Ohio Companies, filed applications for rehearing regarding the Ohio Companies’ ESP IV with the PUCO. The Ohio Companies’ application for rehearing challenged, among other things, the PUCO’s failure to adopt the Ohio Companies’ suggested modifications to Rider DMR. The Ohio Companies had previously suggested that a properly designed Rider DMR would be valued at $558 million annually for eight years, and include an additional amount that recognizes the value of the economic impact of FirstEnergy maintaining its headquarters in Ohio. Other parties’ applications for rehearing argued, among other things, that the PUCO’s adoption of Rider DMR is not supported by law or sufficient evidence. On August 16, 2017, the PUCO denied all remaining intervenor applications for rehearing, denied the Ohio Companies’ challenges to the modifications to Rider DMR and added a third-party monitor to ensure that Rider DMR funds are spent appropriately. On September 15, 2017, the Ohio Companies filed an application for rehearing of the PUCO’s August 16, 2017 ruling on the issues of the third-party monitor and the ROE calculation for advanced metering infrastructure. On October 11, 2017, the PUCO denied the Ohio Companies' application for rehearing on both issues. On October 16, 2017, the Sierra Club and the Ohio Manufacturer's Association Energy Group filed notices of appeal with the Supreme Court of Ohio appealing various PUCO entries on their applications for rehearing. On November 16, 2017, the Ohio Companies intervened in the appeal. Additional parties subsequently filed notices of appeal with the Supreme Court of Ohio challenging various PUCO entries on their applications for rehearing. For additional information, see “FERC Matters - Ohio ESP IV PPA,” below.

Under ORC 4928.66, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. Starting in 2017, ORC 4928.66 requires the energy savings benchmark to increase by 1% and the peak demand reduction benchmark to increase by 0.75% annually thereafter through 2020 and the energy savings benchmark to increase by 2% annually from 2021 through 2027, with a cumulative benchmark of 22.2% by 2027. On April 15, 2016, the Ohio Companies filed an application for approval of their three-year energy efficiency portfolio plans for the period from January 1, 2017 through December 31, 2019. The plans as proposed comply with benchmarks contemplated by ORC 4928.66 and provisions of the ESP IV, and include a portfolio of energy efficiency programs targeted to a variety of customer segments, including residential customers, low income customers, small commercial customers, large commercial and industrial customers and governmental entities. On December 9, 2016, the Ohio Companies filed a Stipulation and Recommendation with several parties that contained changes to the plan and a decrease in the plan costs. The Ohio Companies anticipate the cost of the plans will be approximately $268 million over the life of the portfolio plans and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. On November 21, 2017, the PUCO issued an order that approved the filed Stipulation and Recommendation with several modifications, including a cap on the Ohio Companies’ collection of program costs and shared savings set at 4% of the Ohio Companies’ total sales to customers as reported on FERC Form 1. On December 21, 2017, the Ohio Companies filed an application for rehearing challenging the PUCO’s modification of the Stipulation and Recommendation to include the 4% cost cap, which was denied by the PUCO on January 10, 2018.


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Ohio law requires electric utilities and electric service companies in Ohio to serve part of their load from renewable energy resources measured by an annually increasing percentage amount through 2026, except that in 2014 SB310 froze 2015 and 2016 requirements at the 2014 level (2.5%), pushing back scheduled increases, which resumed in 2017 (3.5%), and increases 1% each year through 2026 (to 12.5%) and shall remain at 12.5% in 2027 and each year thereafter. The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet these renewable energy requirements. In September 2011, the PUCO opened a docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies recover the costs of acquiring these RECs. The PUCO issued an Opinion and Order on August 7, 2013, approving the Ohio Companies' acquisition process and their purchases of RECs to meet statutory mandates in all instances except for certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount of $43.4 million, plus interest, on the basis that the Ohio Companies did not prove such purchases were prudent. On December 24, 2013, following the denial of their application for rehearing, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio, which was granted. The OCC and the ELPC also filed appeals of the PUCO's order. On January 24, 2018, the Supreme Court of Ohio reversed the PUCO order finding that the order violated the rule against prohibiting retroactive ratemaking. On February 5, 2018, the OCC and ELPC filed a motion for reconsideration, to which the Ohio Companies responded in opposition on February 15, 2018.

On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges. On November 18, 2015, the PUCO ruled that on a going-forward basis, pass-through clauses may not be included in fixed-price contracts for all customer classes. On December 18, 2015, FES filed an Application for Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers. On January 13, 2016, the PUCO granted reconsideration for further consideration of the matters specified in the applications for rehearing. On March 29, 2017, the PUCO issued a Second Entry on Rehearing that granted, in part, the applications for rehearing filed by FES and other parties, finding that the PUCO’s guidelines regarding fixed-price contracts should not apply to large mercantile customers. This finding changes the original order, which applied the guidelines to all customers, including mercantile customers. The PUCO also reaffirmed several provisions of the original order, including that the fixed-price guidelines only apply on a going-forward basis and not to existing contracts and that regulatory-out clauses in contracts are permissible.

On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM Plan. The DPM Plan is a portfolio of approximately $450 million in distribution platform investment projects, which are designed to modernize the Ohio Companies’ distribution grid, prepare it for further grid modernization projects, and provide customers with immediate reliability benefits. The Ohio Companies have requested that the PUCO issue an order approving the DPM Plan and associated cost recovery no later than May 2, 2018, so that the Ohio Companies can expeditiously commence the DPM Plan and customers can begin to realize the associated benefits.

On January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act and determine the appropriate course of action to pass benefits on to customers. The Ohio Companies must establish a regulatory liability, effective January 1, 2018, for the estimated reduction in federal income tax resulting from the Tax Act, and filed comments on February 15, 2018, explaining that customers will save nearly $40 million annually as a result of updating tariff riders for the tax rate changes and that the Ohio Companies’ base distribution rates are not impacted by the Tax Act changes because they are frozen through May 2024.
Pennsylvania Regulatory Matters

The Pennsylvania Companies operate under DSPs for the June 1, 2017 through May 31, 2019 delivery period, which provide for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. Under the DSPs, the supply will be provided by wholesale suppliers through a mix of 12 and 24-month energy contracts, as well as one RFP for 2-year SREC contracts for ME, PN and Penn. The DSPs include modifications to the Pennsylvania Companies’ POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges.

On December 11, 2017, the Pennsylvania Companies filed DSPs for the June 1, 2019 through May 31, 2023 delivery period. Under the 2019-2023 DSPs, the supply is proposed to be provided by wholesale suppliers through a mix of 3, 12 and 24-month energy contracts, as well as two RFPs for 2-year SREC contracts for ME, PN and Penn. The 2019-2023 DSPs as proposed also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program term. The 2019-2023 DSPs also introduce a retail market enhancement rate mechanism designed to stimulate residential customer shopping, and modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW. A hearing has been scheduled for April 10-11, 2018, and the PPUC is expected to issue a final order on these DSPs by mid-September 2018.

The Pennsylvania Companies operate under rates that were approved by the PPUC on January 19, 2017, effective as of January 27, 2017. These rates provide annual increases in operating revenues of approximately $96 million at ME, $100 million at PN, $29 million at Penn, and $66 million at WP, and are intended to benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements.


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Pursuant to Pennsylvania's EE&C legislation in Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting: demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at 1.8% for ME, 1.7% for Penn, 1.8% for WP, and 0% for PN; and energy consumption reduction targets, as a percentage of each Pennsylvania Companies’ historic 2010 forecasts (in MWH), at 4.0% for ME, 3.9% for PN, 3.3% for Penn, and 2.6% for WP. The Pennsylvania Companies' Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, with expected costs up to $390 million, are designed to achieve the targets established in the PPUC's Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders.

Pursuant to Act 11 of 2012, Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. Pennsylvania EDCs must file LTIIPs outlining infrastructure improvement plans for PPUC review and approval prior to approval of a DSIC. On February 11, 2016, the PPUC approved LTIIPs for each of the Pennsylvania Companies. On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. The LTIIPs estimated costs for the remaining period of 2018 to 2020, as modified, are: WP $50.1 million; PN $44.8 million; Penn $33.2 million; and ME $51.3 million.

On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery, which were approved by the PPUC on June 9, 2016, and went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. On January 19, 2017, in the PPUC’s order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016, which is pending PPUC approval. The ADIT issue is subject to further litigation and a hearing was held on May 12, 2017. On August 31, 2017, the ALJ issued a decision recommending that the complaint of the Pennsylvania OCA be granted by the PPUC such that the Pennsylvania Companies reflect all federal and state income tax deductions related to DSIC-eligible property in the currently effective DSIC rates. If the decision is approved by the PPUC, the impact is not expected to be material to FirstEnergy. The Pennsylvania Companies filed exceptions to the decision on September 20, 2017, and reply exceptions on October 2, 2017.

On February 12, 2018, the PPUC initiated a proceeding to determine the effects of the Tax Act on the tax liability of utilities and the feasibility of reflecting such impacts in rates charged to customers. By March 9, 2018, the Pennsylvania Companies must submit information to the PPUC to calculate the net effect of the Tax Act on income tax expense and rate base, and comments addressing whether rates should be adjusted to reflect the tax rate changes, and if so, how and when such modifications should take effect.
West Virginia Regulatory Matters

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP's and PE's ENEC rate is updated annually.

On September 23, 2016, the WVPSC approved the Phase II energy efficiency program for MP and PE as reflected in a unanimous settlement by the parties to the proceeding, which includes three energy efficiency programs to meet the Phase II requirement of energy efficiency reductions of 0.5% of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period, which was approved by the WVPSC in the 2012 proceeding approving the transfer of ownership of Harrison Power Station to MP. The costs for the Phase II program are expected to be $10.4 million and are eligible for recovery through the existing energy efficiency rider which is reviewed in the fuel (ENEC) case each year. On December 15, 2017, the WVPSC approved MP's and PE's proposed annual decrease in their EE&C rates, effective January 1, 2018, which is not material to FirstEnergy.

On December 9, 2016, the WVPSC approved the annual ENEC case for MP and PE as reflected in a unanimous settlement by the parties to the proceeding, resulting in an increase in the ENEC rate of $25 million annually beginning January 1, 2017. In addition, ENEC rates will be maintained at the same level for a two year period.

On December 30, 2015, MP and PE filed an IRP with the WVPSC identifying a capacity shortfall starting in 2016 and exceeding 700 MWs by 2020 and 850 MWs by 2027. On June 3, 2016, the WVPSC accepted the IRP. On December 16, 2016, MP issued an RFP to address its generation shortfall, along with issuing a second RFP to sell its interest in Bath County. Bids were received by an independent evaluator in February 2017 for both RFPs. AE Supply was the winning bidder of the RFP to address MP’s generation shortfall and on March 6, 2017, MP and AE Supply signed an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station (1,300 MWs) for approximately $195 million, subject to customary and other closing conditions, including regulatory approvals. In addition, on March 7, 2017, MP and PE filed an application with the WVPSC and MP and AE Supply filed an application with FERC requesting authorization for such purchase. Various intervenors filed protests challenging the RFP and requesting FERC deny the application, set it for hearing to allow discovery into the RFP process, or delay an order pending the conclusion of the WVPSC proceeding. On January 12, 2018, FERC issued an order denying authorization for the transaction, holding that MP and AE Supply did not demonstrate that the sale was consistent with the public interest and the transaction did not fall within the safe harbors for meeting FERC’s affiliate cross-subsidization analysis. In the order FERC also revised and clarified certain details of its standards for the review of transactions resulting from competitive solicitations, and concluded that MP’s RFP did not meet the revised and clarified standards. FERC allowed that MP may submit a future application for a transaction resulting from a new RFP.

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The WVPSC issued its order on January 26, 2018, denying the petition as filed but granting the transfer of Pleasants Power Station under certain conditions, which included MP assuming significant commodity risk. MP, PE and AE Supply have determined not to seek rehearing at FERC in light of the adverse decisions at FERC and the WVPSC. Based on the FERC ruling and the conditions included in the WVPSC order, MP and AE Supply terminated the asset purchase agreement. With respect to the Bath County RFP, MP does not plan to move forward with that sale of its ownership interest. In the future, MP may re-evaluate its options with respect to its interest in Bath County.

On September 1, 2017, MP and PE filed with the WVPSC for a reconciliation of their VMS to confirm that rate recovery matches VMP costs and for a regular review of that program. MP and PE proposed a $15 million annual decrease in VMS rates effective January 1, 2018, and an additional $15 million decrease in rates for 2019. This is an overall decrease in total revenue and average rates of 1%. On December 15, 2017, the WVPSC issued an order adopting a unanimous settlement without modification.

On January 3, 2018, the WVPSC initiated a proceeding to investigate the effects of the Tax Act on the revenue requirements of utilities. MP and PE must track the tax savings resulting from the Tax Act on a monthly basis, effective January 1, 2018, and file written testimony explaining the impact of the Tax Act on federal income tax and revenue requirements by May 30, 2018. On January 26, 2018, the WVPSC issued an order clarifying that regulatory accounting should be implemented as of January 1, 2018, including the recording of any regulatory liabilities resulting from the Tax Act.
FERC Matters

Ohio ESP IV PPA

On August 4, 2014, the Ohio Companies filed an application with the PUCO seeking approval of their ESP IV. ESP IV included a proposed Rider RRS, which would flow through to customers either charges or credits representing the net result of the price paid to FES through an eight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, against the revenues received from selling such output into the PJM markets. The Ohio Companies entered into stipulations which modified ESP IV, and on March 31, 2016, the PUCO issued an Opinion and Order adopting and approving the Ohio Companies’ stipulated ESP IV with modifications. FES and the Ohio Companies entered into the ESP IV PPA on April 1, 2016, but subsequently agreed to suspend it and advised FERC of this course of action.

On March 21, 2016, a number of generation owners filed with FERC a complaint against PJM requesting that FERC expand the MOPR in the PJM Tariff to prevent the alleged artificial suppression of prices in the PJM capacity markets by state-subsidized generation, in particular alleged price suppression that could result from the ESP IV PPA and other similar agreements. The complaint requested that FERC direct PJM to initiate a stakeholder process to develop a long-term MOPR reform for existing resources that receive out-of-market revenue. On January 9, 2017, the generation owners filed to amend their complaint to include challenges to certain legislation and regulatory programs in Illinois. On January 24, 2017, FESC, acting on behalf of its affected affiliates and along with other utility companies, filed a motion to dismiss the amended complaint for various reasons, including that the ESP IV PPA matter is now moot. In addition, on January 30, 2017, FESC along with other utility companies filed a substantive protest to the amended complaint, demonstrating that the question of the proper role for state participation in generation development should be addressed in the PJM stakeholder process. On August 30, 2017, the generation owners requested expedited action by FERC. This proceeding remains pending before FERC.

PJM Transmission Rates

PJM and its stakeholders have been debating the proper method to allocate costs for certain transmission facilities. While FirstEnergy and other parties advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM. This question has been the subject of extensive litigation before FERC and the appellate courts, including before the Seventh Circuit. On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines. The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole. The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings. On June 15, 2016, various parties, including ATSI and the Utilities, filed a settlement agreement at FERC agreeing to apply a combined usage based/socialization approach to cost allocation for charges to transmission customers in the PJM Region for transmission projects operating at or above 500 kV. Certain other parties in the proceeding did not agree to the settlement and filed protests to the settlement seeking, among other issues, to strike certain of the evidence advanced by FirstEnergy and certain of the other settling parties in support of the settlement, as well as provided further comments in opposition to the settlement. FirstEnergy and certain of the other parties responded to such opposition. On October 20, 2017, the settling and non-opposing parties requested expedited action by FERC. The settlement is pending before FERC.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone transferred from MISO to PJM. While many of the matters involved with the move have

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been resolved, FERC denied recovery under ATSI's transmission rate for certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation charges totaling approximately $78.8 million until such time as ATSI submits a cost/benefit analysis demonstrating net benefits to customers from the transfer to PJM. Subsequently, FERC rejected a proposed settlement agreement to resolve the exit fee and transmission cost allocation issues, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. On March 17, 2016, FERC denied FirstEnergy's request for rehearing of FERC's earlier order rejecting the settlement agreement and affirmed its prior ruling that ATSI must submit the cost/benefit analysis.

Separately, ATSI resolved a dispute regarding responsibility for certain costs for the “Michigan Thumb” transmission project. Potential responsibility arises under the MISO MVP tariff, which has been litigated in complex proceedings before FERC and certain U.S. appellate courts. On October 29, 2015, FERC issued an order finding that ATSI and the ATSI zone do not have to pay MISO MVP charges for the Michigan Thumb transmission project. MISO and the MISO TOs filed a request for rehearing, which FERC denied on May 19, 2016. The MISO TOs subsequently filed an appeal of FERC's orders with the Sixth Circuit. FirstEnergy intervened and participated in the proceedings on behalf of ATSI, the Ohio Companies and Penn. On June 21, 2017, the Sixth Circuit issued its decision denying the MISO TOs' appeal request. MISO and the MISO TOs did not seek review by the U.S. Supreme Court, effectively resolving the dispute over the "Michigan Thumb" transmission project. On a related issue, FirstEnergy joined certain other PJM TOs in a protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region. On July 13, 2016, FERC issued its order finding it appropriate for MISO to assess an MVP usage charge for transmission exports from MISO to PJM. Various parties, including FirstEnergy and the PJM TOs, requested rehearing or clarification of FERC’s order. The requests for rehearing remain pending before FERC.

In addition, in a May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM approved before ATSI joined PJM could be charged to transmission customers in the ATSI zone. The amount to be paid, and the question of derived benefits, is pending before FERC as a result of the Seventh Circuit's June 25, 2014 order described above under "PJM Transmission Rates."

The outcome of the proceedings that address the remaining open issues related to MVP costs and "legacy RTEP" transmission projects cannot be predicted at this time.

Transfer of Transmission Assets to MAIT

Following receipt of necessary regulatory approvals, on January 31, 2017, MAIT issued membership interests to FET, PN and ME in exchange for their respective cash and transmission asset contributions. MAIT, a transmission-only subsidiary of FET, owns and operates all of the FERC-jurisdictional transmission assets previously owned by ME and PN. Subsequently, on March 13, 2017, FERC issued an order authorizing MAIT to issue short- and long-term debt securities, permitting MAIT to participate in the FirstEnergy regulated companies’ money pool for working capital, to fund day-to-day operations, support capital investment and establish an actual capital structure for ratemaking purposes.

MAIT Transmission Formula Rate

On October 28, 2016, as amended on January 10, 2017, MAIT submitted an application to FERC requesting authorization to implement a forward-looking formula transmission rate to recover and earn a return on transmission assets effective February 1, 2017. Various intervenors submitted protests of the proposed MAIT formula rate. Among other things, the protest asked FERC to suspend the proposed effective date for the formula rate until June 1, 2017. On March 10, 2017, FERC issued an order accepting the MAIT formula transmission rate for filing, suspending the formula transmission rate for five months to become effective July 1, 2017, and establishing hearing and settlement judge procedures. On April 10, 2017, MAIT requested rehearing of FERC’s decision to suspend the effective date of the formula rate. FERC's order on rehearing remains pending. MAIT’s rates went into effect on July 1, 2017, subject to refund pending the outcome of the hearing and settlement procedures. On October 13, 2017, MAIT and certain parties filed a settlement agreement with FERC. The settlement agreement provides for certain changes to MAIT's formula rate, changes MAIT's ROE from 11% to 10.3%, sets the recovery amount for certain regulatory assets, and establishes that MAIT's capital structure will not exceed 60% equity over the period ending December 31, 2021. The settlement agreement further provides that the ROE and the 60% cap on the equity component of MAIT's capital structure will remain in effect unless changed pursuant to section 205 or 206 of the FPA provided the effective date for any change shall be no earlier than January 1, 2022. The settlement agreement currently is pending at FERC. As a result of the settlement agreement, MAIT recognized a pre-tax impairment charge of $13 million in the third quarter of 2017.

JCP&L Transmission Formula Rate

On October 28, 2016, after withdrawing its request to the NJBPU to transfer its transmission assets to MAIT, JCP&L submitted an application to FERC requesting authorization to implement a forward-looking formula transmission rate to recover and earn a return on transmission assets effective January 1, 2017. A group of intervenors, including the NJBPU and New Jersey Division of Rate Counsel, filed a protest of the proposed JCP&L transmission rate. Among other things, the protest asked FERC to suspend the proposed effective date for the formula rate until June 1, 2017. On March 10, 2017, FERC issued an order accepting the JCP&L formula transmission rate for filing, suspending the transmission rate for five months to become effective June 1, 2017, and establishing hearing and settlement judge procedures. On April 10, 2017, JCP&L requested rehearing of FERC’s decision to suspend

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the effective date of the formula rate. FERC's order on rehearing remains pending. JCP&L’s rates went into effect on June 1, 2017, subject to refund pending the outcome of the hearing and settlement procedures. On December 21, 2017, JCP&L and certain parties filed a settlement agreement with FERC. The settlement agreement provides for a $135 million stated annual revenue requirement for Network Integration Transmission Service and an average of $20 million stated annual revenue requirement for certain projects listed on the PJM Tariff where the costs are allocated in part beyond the JCP&L transmission zone within the PJM Region. The revenue requirements are subject to a moratorium on additional revenue requirements proceedings through December 31, 2019, other than limited filings to seek recovery for certain additional costs. Also on December 21, 2017, JCP&L filed a motion for authorization to implement the settlement rate on an interim basis. On December 27, 2017, FERC granted the motion authorizing JCP&L to implement the settlement rate effective January 1, 2018, pending a final commission order on the settlement agreement. The settlement agreement is pending at FERC. As a result of the settlement agreement, JCP&L recognized a pre-tax impairment charge of $28 million in the fourth quarter of 2017.

DOE NOPR: Grid Reliability and Resilience Pricing

On September 28, 2017, the Secretary of Energy released a NOPR requesting FERC to issue rules directing RTOs to incorporate pricing for defined “eligible grid reliability and resiliency resources” into wholesale energy markets. Specifically, as proposed, RTOs would develop and implement tariffs providing a just and reasonable rate for energy purchases from eligible grid reliability and resiliency resources and the recovery of fully allocated costs and a fair ROE. The NOPR followed the August 23, 2017, release of the DOE’s study regarding whether federally controlled wholesale energy markets properly recognize the importance of coal and nuclear plants for the reliability of the high-voltage grid, as well as whether federal policies supporting renewable energy sources have harmed the reliability of the energy grid. The DOE requested for the final rules to be effective in January 2018.

On October 2, 2017, FERC established a docket and requested comments on the NOPR. FESC and certain of its affiliates submitted comments and reply comments. On January 8, 2018, FERC issued an order terminating the NOPR proceeding, finding that the NOPR did not satisfy the statutory threshold requirements under the FPA for requiring changes to RTO/ISO tariffs to address resilience concerns. FERC in its order instituted a new administrative proceeding to gather additional information regarding resilience issues, and directed that each RTO/ISO respond to a provided list of questions. There is no deadline or requirement for FERC to act in this new proceeding. At this time, we are uncertain as to the potential impact that final action by FERC, if any, would have on FES and our strategic options, and the timing thereof, with respect to the competitive business.

Competitive Generation Asset Sale

FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement with a subsidiary of LS Power, as amended and restated in August 2017, to sell four natural gas generating plants, AE Supply's interest in the Buchanan Generating facility and approximately 59% of AGC's interest in Bath County (1,615 MWs of combined capacity) for an all-cash purchase price of $825 million, subject to adjustments and through multiple, independent closings. On December 13, 2017, AE Supply completed the sale of the natural gas generating plants with net proceeds, subject to post-closing adjustments, of approximately $388 million. The sale of AE Supply's interests in the Bath County hydroelectric power station and the Buchanan Generating facility is expected to generate net proceeds of $375 million and is anticipated to close in the first half of 2018, subject in each case to various customary and other closing conditions, including, without limitation, receipt of regulatory approvals.

As part of the closing of the natural gas generating plants, FE provided the purchaser two limited three-year guarantees totaling $555 million of certain obligations of AE Supply and AGC arising under the amended and restated purchase agreement.

With the sale of the gas plants completed, upon the consummation of the sale of AGC's interest in the Bath County hydroelectric power station or the sale or deactivation of the Pleasants Power Station, AE Supply is obligated under the amended and restated purchase agreement and AE Supply's applicable debt agreements to satisfy and discharge approximately $305 million of currently outstanding senior notes, as well as its $142 million of pollution control notes and AGC's $100 million senior notes, which are expected to require the payment of "make-whole" premiums currently estimated to be approximately $95 million based on current interest rates.

On October 20, 2017, the parties filed an application with the VSCC for approval of the sale of approximately 59% of AGC's interest in the Bath County hydroelectric power station. On December 12, 2017, FERC issued an order authorizing the partial transfer of the related hydroelectric license for Bath County under Part I of the FPA. In December 2017, AGC, AE Supply and MP filed with FERC and AGC and AE Supply filed with the VSCC, applications for approval of AGC redeeming AE Supply’s shares in AGC upon consummation of the Bath County transaction. On February 2, 2018, the VSCC issued an order finding that approval of the proposed stock redemption is not required, and on February 16, 2018, FERC issued an order authorizing the redemption. Upon the consummation of the redemption, AGC will become a wholly-owned subsidiary of MP.

On December 28, 2017, FERC issued an order authorizing the sale of BU Energy’s Buchanan interests. Additional filings have been submitted to FERC for the purpose of amending affected FERC-jurisdictional rates and implementing the transaction once the sales are consummated. There can be no assurance that all regulatory approvals will be obtained and/or all closing conditions will be satisfied or that the remaining transactions will be consummated.


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As a result of the amended asset purchase agreement, CES recorded non-cash pre-tax impairment charges of $193 million in 2017, reflecting the $825 million purchase price as well as certain purchase price adjustments based on timing of the closing of the transaction.

PATH Transmission Project

In 2012, the PJM Board of Managers canceled the PATH project, a proposed transmission line from West Virginia through Virginia and into Maryland. As a result of PJM canceling the project, approximately $62 million and approximately $59 million in costs incurred by PATH-Allegheny and PATH-WV, respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery. PATH-Allegheny and PATH-WV requested authorization from FERC to recover the costs with a proposed ROE of 10.9% (10.4% base plus 0.5% for RTO membership) from PJM customers over five years. FERC issued an order denying the 0.5% ROE adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012, subject to hearing and settlement procedures. On January 19, 2017, FERC issued an order reducing the PATH formula rate ROE from 10.4% to 8.11% effective January 19, 2017, and allowing recovery of certain related costs. On February 21, 2017, PATH filed a request for rehearing with FERC, seeking recovery of disallowed costs and requesting that the ROE be reset to 10.4%. The Edison Electric Institute submitted an amicus curiae request for reconsideration in support of PATH. On March 20, 2017, PATH also submitted a compliance filing implementing the January 19, 2017 order. Certain affected ratepayers commented on the compliance filing, alleging inaccuracies in and lack of transparency of data and information in the compliance filing, and requested that PATH be directed to recalculate the refund provided in the filing. PATH responded to these comments in a filing that was submitted on May 22, 2017. On July 27, 2017, FERC Staff issued a letter to PATH requesting additional information on, and edits to, the compliance filing, as directed by the January 19, 2017 order. PATH filed its response on September 27, 2017. FERC orders on PATH's requests for rehearing and compliance filing remain pending.

Market-Based Rate Authority, Triennial Update

The Utilities, AE Supply, FES and certain of its subsidiaries, Buchanan Generation and Green Valley each hold authority from FERC to sell electricity at market-based rates. One condition for retaining this authority is that every three years each entity must file an update with FERC that demonstrates that each entity continues to meet FERC’s requirements for holding market-based rate authority. On December 23, 2016, FESC, on behalf of its affiliates with market-based rate authority, submitted to FERC the most recent triennial market power analysis filing for each market-based rate holder for the current cycle of this filing requirement. On July 27, 2017, FERC accepted the triennial filing as submitted.
Capital Requirements

FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest payments, dividend payments and contributions to its pension plan.

On January 22, 2018, FirstEnergy announced a $2.5 billion equity issuance, which included $1.62 billion in mandatorily convertible preferred equity with an initial conversion price of $27.42 per share and $850 million of common equity issued at $28.22 per share. The preferred shares will receive the same dividend paid on common stock on an as-converted basis and are non-voting except in certain limited circumstances. The new preferred shares contain an optional conversion for holders beginning in July 2018, and will mandatorily convert in 18-months from the issuance, subject to limited exceptions. Proceeds from the investment were used to reduce holding company debt by $1.45 billion and fund the company’s pension plan by $750 million, with the remainder used for general corporate purposes.

The equity investment allows FirstEnergy to strengthen its balance sheet and supports the company's transition to a fully regulated utility company. By deleveraging the company, the investment will also enable FirstEnergy to enhance its investment grade credit metrics and FirstEnergy does not currently anticipate the need to issue additional equity through at least 2021 outside of its regular stock investment and employee benefit plans.

In addition to this equity investment, FE and its utility and transmission subsidiaries expect their existing sources of liquidity to remain sufficient to meet their respective anticipated obligations. In addition to internal sources to fund liquidity and capital requirements for 2018 and beyond, FE and its utility and transmission subsidiaries expect to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through the issuance of long-term debt at certain utility and transmission subsidiaries to, among other things, fund capital expenditures and refinance short-term and maturing long-term debt, subject to market conditions and other factors.

FirstEnergy’s unregulated subsidiaries, specifically FES and AE Supply, expect to rely on, in the case of AE Supply, internal sources, an unregulated companies' money pool (which also includes FE, FET, FEV and certain other unregulated subsidiaries of FE but excludes FENOC, FES and its subsidiaries) and proceeds generated from previously disclosed asset sales, subject to closing, and in the case of FES, its current access to a separate unregulated companies' money pool, which includes FE, FES' subsidiaries and FENOC, and a two-year secured line of credit from FE of up to $500 million, as further described below.


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FES subsidiaries have debt maturities of $515 million in 2018, (excluding intra-company debt), beginning with a $100 million principal payment due April 2, 2018. Based on FES' current senior unsecured debt rating, capital structure and long-term cash flow projections, the debt maturities are unlikely to be refinanced. Although management continues to explore cost reductions and other options to improve cash flow, these obligations and their impact to liquidity raise substantial doubt about FES’ ability to meet its obligations as they come due over the next twelve months and, as such, its ability to continue as a going concern. Furthermore, the inability to obtain legislative support under the Department of Energy’s recent NOPR, which was rejected by FERC, limits FES’ strategic options to plant deactivations, restructuring its debt and other financial obligations with its creditors, and/or to seek protection under U.S. bankruptcy laws.

In 2016, FirstEnergy satisfied its minimum required funding obligations of $382 million and addressed 2017 funding obligations to its qualified pension plan with total contributions of $882 million (of which $138 million was cash contributions from FES), including $500 million of FE common stock contributed to the qualified pension plan on December 13, 2016. In January 2018, FirstEnergy satisfied its minimum required funding obligations of $500 million and, as discussed above, addressed funding obligations for future years to its qualified pension plan with additional contributions of $750 million.

FirstEnergy's capital expenditures for 2018 are expected to be approximately $2.6 billion to $2.9 billion, excluding CES. Planned capital initiatives are intended to promote reliability, improve operations, and support current environmental and energy efficiency directives.

Capital expenditures for 2017 and anticipated expenditures for 2018 by reportable segment are included below:
Reportable Segment
 
2017 Actual(1)
 
2017 Pension/OPEB Mark-to-Market Capital Adjustment
 
2017 Actual Excluding Pension/OPEB Mark-to-Market Capital Costs
 
2018 Forecast(2)
 
 
 
(In millions)
 
Regulated Distribution
 
$
1,342

 
$
(20
)
 
$
1,362

 
$1,500 - $1,600

 
Regulated Transmission
 
1,032

 
1

 
1,031

 
1,000 - 1,200

 
CES
 
279

 
(1
)
 
280

 

(3) 
Corporate/Other
 
99

 

 
99

 
100

 
Total
 
$
2,752

 
$
(20
)
 
$
2,772

 
$2,600 - $2,900

 

(1) Includes a decrease of approximately $20 million related to the capital component of the pension and OPEB mark-to-market adjustment.
(2) Excludes the capital component for pension and OPEB mark-to-market adjustments, which cannot be estimated.
(3) Planned capital expenditures will be dependent on the outcome of the strategic review of CES.

Additionally, planned capital expenditures for Regulated Distribution includes $1.4 billion to $1.7 billion, annually, 2019 through 2021, while planned capital expenditures for Regulated Transmission are expected to be approximately $1.0 billion to $1.2 billion, annually, 2019 through 2021.

15





Capital expenditures for 2017 and 2018 forecast by subsidiary are included in the following table.
Operating Company
 
2017 Actual(1)
 
2017 Pension/OPEB Mark-to-Market Capital Adjustment
 
2017 Actual Excluding Pension/OPEB Mark-to-Market Capital Costs
 
2018 Forecast(2)(3)
 
 
 
(In millions)
OE
 
$
143

 
$
(12
)
 
$
155

 
$
160

 
Penn
 
55

 
(1
)
 
56

 
45

 
CEI
 
134

 
4

 
130

 
145

 
TE
 
37

 
(3
)
 
40

 
50

 
JCP&L
 
317

 
3

 
314

 
380

 
ME
 
142

 
(4
)
 
146

 
185

 
PN
 
162

 
(12
)
 
174

 
195

 
MP
 
269

 
9

 
260

 
280

 
PE
 
112

 

 
112

 
150

 
WP
 
199

 
(2
)
 
201

 
260

 
ATSI
 
541

 

 
541

 
375

 
TrAIL
 
45

 

 
45

 
55

 
FES
 
250

 
(3
)
 
253

 

(4) 
AE Supply
 
34

 
2

 
32

 

(4) 
MAIT
 
242

 
(1
)
 
243

 
400

 
Other subsidiaries
 
70

 

 
70

 
70

 
Total
 
$
2,752

 
$
(20
)
 
$
2,772

 
$
2,750

 

(1) Includes a decrease of approximately $20 million related to the capital component of the pension and OPEB mark-to-market adjustment.
(2) Excludes the capital component for pension and OPEB mark-to-market adjustments, which cannot be estimated.
(3) 2018 Forecast represents the mid-point of Regulated Distribution and Regulated Transmission's 2018 forecasted capital expenditures.
(4) Planned capital expenditures will be dependent on the outcome of the strategic review of CES.

FirstEnergy's strategy is to focus on investments in its regulated operations. The centerpiece of this strategy is the Energizing the Future transmission plan, pursuant to which FirstEnergy plans to invest $4.0 to $4.8 billion in capital investments from 2018 to 2021, with $4.4 billion in capital investment from 2014 through 2017 to upgrade FirstEnergy's transmission system. This program is focused on projects that enhance system performance, physical security and add operating flexibility and capacity starting with the ATSI system and moving east across FirstEnergy's service territory over time. In total, FirstEnergy has identified over $20 billion in transmission investment opportunities across the 24,500 mile transmission system, making this a continuing platform for investment in the years beyond 2021.

The following table presents scheduled debt repayments for outstanding long-term debt as of December 31, 2017, excluding capital leases for the next five years. PCRBs that are scheduled to be tendered for mandatory purchase prior to maturity are reflected in the applicable year in which such PCRBs are scheduled to be tendered.
 
2018
 
2019-2022
 
Total
 
(In millions)
FirstEnergy
$
1,051

 
$
6,008

 
$
7,059

FES
$
515

 
$
1,948

 
$
2,463



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The following table displays consolidated operating lease commitments as of December 31, 2017.
 
 
 
Operating Leases
 
FirstEnergy
 
FES
 
 
 
(In millions)
 
2018
 
$
146

 
$
101

 
2019
 
128

 
97

 
2020
 
102

 
68

 
2021
 
124

 
93

 
2022
 
111

 
91

 
Years thereafter
 
1,263

 
1,131

 
Total minimum lease payments
 
$
1,874

 
$
1,581

 

FE and the Utilities and FET and its subsidiaries participate in two separate five-year syndicated revolving credit facilities with aggregate commitments of $5.0 billion (Facilities), which are available through December 6, 2021. FE and the Utilities and FET and its subsidiaries may use borrowings under their Facilities for working capital and other general corporate purposes, including intercompany loans and advances by a borrower to any of its subsidiaries. Generally, borrowings under each of the Facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the Facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.

FirstEnergy had $300 million and $2,675 million of short-term borrowings as of December 31, 2017 and 2016, respectively. FirstEnergy’s available liquidity from external sources as of January 31, 2018 was as follows:

Borrower(s)
 
Type
 
Maturity
 
Commitment
 
Available Liquidity
 
 
 
 
 
 
(In millions)
FirstEnergy(1)
 
Revolving
 
December 2021
 
$
4,000

 
$
3,740

FET(2)
 
Revolving
 
December 2021
 
1,000

 
1,000

 
 
 
 
Subtotal
 
$
5,000

 
$
4,740

 
 
 
 
Cash
 

 
358

 
 
 
 
Total
 
$
5,000

 
$
5,098


(1) 
FE and the Utilities. Available liquidity includes impact of $10 million of LOCs issued under various terms.
(2) 
Includes FET, ATSI, MAIT and TrAIL.

FES had $105 million and $101 million of short-term borrowings as of December 31, 2017 and December 31, 2016, respectively. Of such amounts, $102 million and $101 million, respectively, represents a currently outstanding promissory note due April 2, 2018, payable to AE Supply with any additional short-term borrowings representing borrowings under an unregulated companies' money pool, which also includes FE, FET, FEV and certain other unregulated subsidiaries of FE, but excludes FENOC, FES and its subsidiaries. In addition to FES' access to a separate unregulated companies' money pool, which includes FE, FES' subsidiaries and FENOC, FES' available liquidity as of January 31, 2018, was as follows:
Type
 
Commitment
 
Available Liquidity
 
 
(In millions)
    Two-year secured credit facility with FE
 
$
500

 
$
500

Cash
 

 
1

 
 
$
500

 
$
501



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Nuclear Operating Licenses

The following table summarizes the current operating license expiration dates for FES' nuclear facilities in service.
Station
 
In-Service Date
 
Current License Expiration
Beaver Valley Unit 1
 
1976
 
2036
Beaver Valley Unit 2
 
1987
 
2047
Perry
 
1986
 
2026
Davis-Besse
 
1977
 
2037
Nuclear Regulation

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of December 31, 2017, FirstEnergy had approximately $2.7 billion (FES $1.9 billion) invested in external trusts to be used for the decommissioning and environmental remediation of its nuclear generating facilities. The values of FirstEnergy's NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs.

As part of routine inspections of the concrete shield building at Davis-Besse in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011. These inspections revealed that the cracking condition had propagated a small amount in select areas. FENOC's analysis confirms that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions. In a May 28, 2015, Inspection Report regarding the apparent cause evaluation on crack propagation, the NRC issued a non-cited violation for FENOC’s failure to request and obtain a license amendment for its method of evaluating the significance of the shield building cracking. The NRC also concluded that the shield building remained capable of performing its design safety functions despite the identified laminar cracking and that this issue was of very low safety significance. In 2017, FENOC commenced a multi-year effort to implement repairs to the shield building. In addition to these ongoing repairs, FENOC intends to submit a license amendment application to the NRC to reconcile the shield building laminar cracking concern.

FES provides a parental support agreement to NG of up to $400 million. The NRC typically relies on such parental support agreements to provide additional assurance that U.S. merchant nuclear plants, including NG's nuclear units, have the necessary financial resources to maintain safe operations, particularly in the event of extraordinary circumstances. So long as FES remains in the unregulated companies' money pool, the $500 million secured line of credit with FE discussed above provides FES the needed liquidity in order for FES to satisfy its nuclear support obligations to NG.
Nuclear Insurance

The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $13.4 billion (assuming 102 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $450 million; and (ii) $13.0 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $127 million (but not more than $19 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, FirstEnergy’s and NG's maximum potential assessment under these provisions would be $509 million per incident but not more than $76 million in any one year for each incident.

In addition to the public liability insurance provided pursuant to the Price-Anderson Act, NG purchases insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. NG is a Member Insured of NEIL, which provides coverage for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. NG, as the Member Insured and each entity with an insurable interest, purchases policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $1.4 billion for replacement power costs incurred during an outage after an initial 12-week waiting period.

NG, as the Member Insured and each entity with an insurable interest, is insured under property damage insurance provided by NEIL. Under these arrangements, up to $2.75 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. Member Insureds of NEIL pay annual premiums and are subject to retrospective premium assessments if losses exceed the accumulated funds available to the insurer. NG purchases insurance through NEIL that will pay its obligation in the event a retrospective premium call is made by NEIL, subject to the terms of the policy.

FirstEnergy intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of NG's plants exceed the policy limits of the insurance in effect with respect to that plant, to

18




the extent a nuclear incident is determined not to be covered by FirstEnergy’s insurance policies, or to the extent such insurance becomes unavailable in the future, FirstEnergy would remain at risk for such costs.

The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.06 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. FirstEnergy is unable to predict what effect these requirements may have on the availability of insurance proceeds.
Environmental Matters

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Pursuant to a March 28, 2017 executive order, the EPA and other federal agencies are to review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof, in particular with respect to existing environmental regulations, may impact its business, results of operations, cash flows and financial condition.

Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations.

Clean Air Act

FirstEnergy complies with SO2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls, generating more electricity from lower or non-emitting plants and/or using emission allowances.

CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry's bid for a lengthy pause in the litigation and set a briefing schedule. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's and FES' operations may result.

The EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015. The EPA stated the vast majority of U.S. counties will meet the new 70 PPB standard by 2025 due to other federal and state rules and programs but the EPA will designate those counties that fail to attain the new 2015 ozone NAAQS by October 1, 2017. The EPA missed the October 1, 2017, deadline and has not yet promulgated the attainment designations. States will then have roughly three years to develop implementation plans to attain the new 2015 ozone NAAQS. On December 5, 2017, fourteen states and the District of Columbia filed complaints in the U.S. District Court of Northern California seeking an order that the EPA promulgate the attainment designations for the new 2015 ozone NAAQS. Depending on how the EPA and the states implement the new 2015 ozone NAAQS, the future cost of compliance may be material and changes to FirstEnergy’s and FES’ operations may result. In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility's NOx emissions significantly contribute to Delaware's inability to attain the ozone NAAQS. The petition seeks a short-term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. On September 27, 2016, the EPA extended the time frame for acting on the State of Delaware's CAA Section 126 petition by six months to April 7, 2017, but has not taken any further action. On January 2, 2018, the State of Delaware provided the EPA a notice required at least 60 days prior to filing a suit seeking to compel the EPA to either approve or deny the August 2016 CAA Section 126 petition. In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3, Mansfield Unit 1 and Pleasants Units 1 and 2, significantly contribute to Maryland's inability to attain the ozone NAAQS. The petition seeks NOx emission rate limits for the 36 EGUs by May 1, 2017. On January 3, 2017, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to July 15, 2017, but has not taken any further action. On September 27, 2017, and October 4, 2017, the State of Maryland and various environmental organizations filed complaints in the

19




U.S. District Court for the District of Maryland seeking an order that the EPA either approve or deny the CAA Section 126 petition of November 16, 2016. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss.

MATS imposed emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired EGUs effective in April 2015 with averaging of emissions from multiple units located at a single plant. The majority of FirstEnergy's MATS compliance program and related costs have been completed.

On August 3, 2015, FG, a wholly owned subsidiary of FES, submitted to the AAA office in New York, N.Y., a demand for arbitration and statement of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure event that excuses FG’s performance under its coal transportation contract with these parties. Specifically, the dispute arose from a contract for the transportation by BNSF and CSX of a minimum of 3.5 million tons of coal annually through 2025 to certain coal-fired power plants owned by FG that are located in Ohio. As a result of and in compliance with MATS, all plants covered by this contract were deactivated by April 16, 2015. Separately, on August 4, 2015, BNSF and CSX submitted to the AAA office in Washington, D.C., a demand for arbitration and statement of claim against FG alleging that FG breached the contract and that FG’s declaration of a force majeure under the contract is not valid and seeking damages under the contract through 2025. On May 31, 2016, the parties agreed to a stipulation that if FG’s force majeure defense is determined to be wholly or partially invalid, liquidated damages are the sole remedy available to BNSF and CSX. The arbitration panel consolidated the claims and held a hearing in November and December 2016. On April 12, 2017, the arbitration panel ruled on liability in favor of BNSF and CSX. In the liability award, the panel found, among other things, that FG’s demand for declaratory judgment that force majeure excused FG’s performance was denied, that FG breached and repudiated the coal transportation contract and that the panel retains jurisdiction of claims for liquidated damages for the years 2015-2025. On May 1, 2017, FE and FG and CSX and BNSF entered into a definitive settlement agreement, which resolved all claims related to this consolidated proceeding on the terms and conditions set forth below. Pursuant to the settlement agreement, FG will pay CSX and BNSF an aggregate amount equal to $109 million, which is payable in three annual installments, the first of which was made on May 1, 2017. FE agreed to unconditionally and continually guarantee the settlement payments due by FG pursuant to the terms of the settlement agreement. The settlement agreement further provides that in the event of the initiation of bankruptcy proceedings or failure to make timely settlement payments, the unpaid settlement amount will immediately accelerate and become due and payable in full. Further, FE and FG, and CSX and BNSF, agreed to release, waive and discharge each other from any further obligations under the claims covered by the settlement agreement upon payment in full of the settlement amount. Until such time, CSX and BNSF will retain the claims covered by the settlement agreement and in the event of a bankruptcy proceeding with respect to FG, to the extent the remaining settlement payments are not paid in full by FG or FE, CSX and BNSF shall be entitled to seek damages for such claims in an amount to be determined by the arbitration panel or otherwise agreed by the parties.

On December 22, 2016, FG, a wholly owned subsidiary of FES, received a demand for arbitration and statement of claim from BNSF and NS which are the counterparties to the coal transportation contract covering the delivery of 2.5 million tons annually through 2025, for FG’s coal-fired Bay Shore Units 2-4, deactivated on September 1, 2012, as a result of the EPA’s MATS and for FG’s W.H. Sammis generating station. The demand for arbitration was submitted to the AAA office in Washington, D.C., against FG alleging, among other things, that FG breached the agreement in 2015 and 2016 and repudiated the agreement for 2017-2025. The counterparties are seeking liquidated damages through 2025, and a declaratory judgment that FG's claim of force majeure is invalid. The arbitration hearing is scheduled for June 2018. The parties have exchanged settlement proposals to resolve all claims related to this proceeding, however, discussions have been terminated and settlement is unlikely. FirstEnergy and FES recorded a pre-tax charge of $116 million in 2017 based on an estimated range of losses regarding the ongoing litigation with respect to this agreement. If the case proceeds to arbitration, the amount of damages owed to BNSF and NS could be materially higher and may cause FES to seek protection under U.S. bankruptcy laws. FG intends to vigorously assert its position in this arbitration proceeding, and if it were ultimately determined that the force majeure provisions or other defenses do not excuse the delivery shortfalls, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.

As to a specific coal supply agreement, AE Supply, the party thereto, asserted termination rights effective in 2015 as a result of MATS. In response to notification of the termination, on January 15, 2015, Tunnel Ridge, LLC, the coal supplier, commenced litigation in the Court of Common Pleas of Allegheny County, Pennsylvania, alleging AE Supply did not have sufficient justification to terminate the agreement and seeking damages for the difference between the market and contract price of the coal, or lost profits plus incidental damages. AE Supply filed an answer denying any liability related to the termination. On May 1, 2017, the complaint was amended to add FE, FES and FG, although not parties to the underlying contract, as defendants and to seek additional damages based on new claims of fraud, unjust enrichment, promissory estoppel and alter ego. On June 27, 2017, after oral argument, defendants' preliminary objections to the amended complaint were denied. On February 18, 2018, the parties reached an agreement in principle settling all claims in dispute. The agreement in principle includes, among other matters, a $93 million payment by AE Supply, as well as certain coal supply commitments for Pleasants Power Station during its remaining operation by AE Supply. Certain aspects of the final settlement agreement will be guaranteed by FE, including the $93 million payment.

In September 2007, AE received an NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia. The EPA's NOV alleges equipment replacements during maintenance outages triggered the pre-construction permitting requirements under the NSR and PSD programs. On June 29, 2012, January 31, 2013, March 27, 2013 and October 18, 2016, the EPA issued CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. On December 12, 2014,

20




the EPA issued a CAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2009. FirstEnergy intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the loss or range of loss.
 
Climate Change

FirstEnergy has established a goal to reduce CO2 emissions by 90% below 2005 levels by 2045. There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.

The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act,” in December 2009, concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. On June 23, 2014, the U.S. Supreme Court decided that CO2 or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by the EPA to install GHG control technologies. The EPA released its final CPP regulations in August 2015 (which have been stayed by the U.S. Supreme Court), to reduce CO2 emissions from existing fossil fuel-fired EGUs. The EPA also finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On January 21, 2016, a panel of the D.C. Circuit denied the motions for stay and set an expedited schedule for briefing and argument. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October 16, 2017, the EPA issued a proposed rule to repeal the CPP. Depending on the outcomes of the review pursuant to the executive order, of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.

At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide GHG emissions by 26 to 28 percent below 2005 levels by 2025 and in September 2016, joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement was ratified by the requisite number of countries (i.e., at least 55 countries representing at least 55% of global GHG emissions) in October 2016 and its non-binding obligations to limit global warming to well below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations.

The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. Depending on any final action taken by the states with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material.

On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations phase-in as permits are renewed on a five-year cycle from 2018 to 2023. The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporative technology and in return have until the end of 2023 to meet the more stringent limits. On April 13, 2017, the EPA granted a Petition for Reconsideration and administratively stayed (effective upon publication in the Federal Register) all deadlines in the effluent limits rule pending a new rulemaking. Also, on September 18, 2017, the EPA postponed certain compliance deadlines for two years. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's and FES' operations may result.


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In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES permit, WVDEP also issued an administrative order setting deadlines for MP to meet certain of the effluent limits that were effective immediately under the terms of the NPDES permit. MP appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require an initial capital investment ranging from $150 million to $300 million in order to install technology to meet the TDS and sulfate limits, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of the appeal or estimate the possible loss or range of loss.

FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the loss or range of loss.

Regulation of Waste Disposal

Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation.

In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although not currently expected, changes in timing and closure plan requirements in the future, including changes resulting from the strategic review at CES, could materially and adversely impact FirstEnergy's and FES' AROs.

Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring the Bruce Mansfield plant to cease disposal of CCRs by December 31, 2016, and FG to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizing FG to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCRs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met. The CCRs from the Bruce Mansfield plant are being beneficially reused with the majority used for reclamation of a site owned by the Marshall County Coal Company in Moundsville, W. Va., and the remainder recycled into drywall by National Gypsum. These beneficial reuse options should be sufficient for ongoing plant operations, however, the Bruce Mansfield plant is pursuing other options. On May 22, 2015 and September 21, 2015, the PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility and then modified that permit to allow disposal of Bruce Mansfield plant CCR. The Sierra Club's Notices of Appeal before the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility were resolved through a Consent Adjudication between FG, PA DEP and the Sierra Club requiring operational changes that became effective November 3, 2017.

FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of December 31, 2017, based on estimates of the total costs of cleanup, FE's and its subsidiaries' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $125 million have been accrued through December 31, 2017. Included in the total are accrued liabilities of approximately $80 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FirstEnergy or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.
Fuel Supply

FirstEnergy currently has coal contracts with various terms to acquire approximately 16 million tons of coal (FES 8 million tons) for the year 2018, which is approximately 97% of its forecasted 2018 coal requirements. This contracted coal is produced primarily from mines located in Pennsylvania and West Virginia. The contracts expire at various times through 2028. See "Environmental Matters," for additional information pertaining to the impact of increased environmental regulations on coal supply and transportation contracts applicable to certain deactivated coal-fired generating units and related pending disputes.

FENOC has contracts for all uranium requirements through 2018 and a portion of uranium material requirements through 2024. Conversion services contracts fully cover requirements through 2018 and partially fill requirements through 2024. Enrichment services are contracted for essentially all of the enrichment requirements for nuclear fuel through 2020. A portion of enrichment

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requirements is also contracted for through 2030. Fabrication services for fuel assemblies are contracted for both Beaver Valley units through 2028 and Davis-Besse through 2024 and through the current operating license period for Perry.

On-site spent fuel storage facilities are currently adequate for the nuclear operating units. An on-site dry cask storage facility has been constructed at Beaver Valley sufficient to extend spent fuel storage capacity through the end of current operating licenses at Beaver Valley Unit 1 and Beaver Valley Unit 2. Davis-Besse resumed dry cask storage operations in 2017, which will extend on-site spent fuel storage capacity through the end of its recently extended operating license. Perry has constructed an on-site dry cask storage facility, has completed three dry cask storage loading campaigns, and has planned to conduct additional dry cask storage loading campaigns that will provide for sufficient spent fuel storage capacity through 2046 (end of current operating license plus a potential 20-year operating license extension).

The Federal Nuclear Waste Policy Act of 1982 provided for the construction of facilities for the permanent disposal of high-level nuclear waste, including spent fuel from nuclear power plants operated by electric utilities. NG has contracts with the DOE for the disposal of spent fuel for Beaver Valley, Davis-Besse and Perry. Yucca Mountain was approved in 2002 as a repository for underground disposal of spent nuclear fuel from nuclear power plants and high level waste from U.S. defense programs. The DOE submitted the license application for Yucca Mountain to the NRC on June 3, 2008. Efforts to complete the Yucca Mountain repository have been suspended and a Federal review of potential alternative strategies has been performed. In light of this uncertainty, FES has made arrangements for storage capacity as a contingency for the continuing delays of the DOE acceptance of spent fuel for disposal.

System Demand
The maximum hourly demand for each of the Utilities was:
System Demand
 
2017
 
2016
 
2015
 
 
(in MWs)
OE
 
5,434

 
5,655

 
5,391

Penn
 
926

 
994

 
983

CEI
 
4,220

 
4,193

 
4,057

TE
 
2,205

 
2,171

 
2,149

JCP&L
 
5,721

 
5,955

 
5,789

ME
 
2,897

 
2,904

 
2,770

PN
 
2,882

 
2,890

 
3,024

MP
 
1,986

 
2,053

 
2,031

PE
 
3,049

 
3,049

 
3,631

WP
 
3,752

 
3,947

 
3,942


Supply Plan

Regulated Commodity Sourcing

Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales can vary depending on the level of shopping that occurs. Supply plans vary by state and by service territory. JCP&L’s default service or BGS supply is secured through a statewide competitive procurement process approved by the NJBPU. Default service for the Ohio Companies, Pennsylvania Companies and PE's Maryland jurisdiction are provided through a competitive procurement process approved by the PUCO (under the ESP), PPUC (under the DSP) and MDPSC (under the SOS), respectively. If any supplier fails to deliver power to any one of those Utilities’ service areas, the Utility serving that area may need to procure the required power in the market in their role as the default LSE. West Virginia electric generation continues to be regulated by the WVPSC.

Unregulated Commodity Sourcing

The CES segment, through FES and AE Supply, primarily provides energy and energy related services, including the generation and sale of electricity and energy planning and procurement through retail and wholesale competitive supply arrangements. FES and AE Supply provide the power requirements of their competitive load-serving obligations through a combination of subsidiary-owned generation, non-affiliated contracts and spot market transactions.


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FES and AE Supply have retail and wholesale competitive load-serving obligations in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey, serving both affiliated and non-affiliated companies. FES and AE Supply provide energy products and services to customers under various POLR, shopping, competitive-bid and non-affiliated contractual obligations. Geographically, most of FES’ and AE Supply's obligations are in the PJM market area where all of their respective generation facilities are located.
Regional Reliability

All of FirstEnergy's facilities are located within the PJM Region and operate under the reliability oversight of a regional entity known as RFC. This regional entity operates under the oversight of NERC in accordance with a delegation agreement approved by FERC.
Competition

Within FirstEnergy’s Regulated Distribution segment, generally there is no competition for electric distribution service in the Utilities’ respective service territories in Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York. Additionally, there has traditionally been no competition for transmission service in PJM. However, pursuant to FERC’s Order No. 1000 and subject to state and local siting and permitting approvals, non-incumbent developers now can compete for certain PJM transmission projects in the service territories of FirstEnergy’s Regulated Transmission segment. This could result in additional competition to build transmission facilities in the Regulated Transmission segment’s service territories while also allowing the Regulated Transmission segment the opportunity to seek to build facilities in non-incumbent service territories.

FirstEnergy's CES segment participates in deregulated energy markets in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, through FES and AE Supply. In these markets, the CES segment competes: (1) to provide retail generation service directly to end users; (2) to provide wholesale generation service to utilities, municipalities and co-operatives, which, in turn, resell to end users and (3) in the wholesale market.
Seasonality

The sale of electric power is generally a seasonal business, and weather patterns can have a material impact on FirstEnergy’s operating results. Demand for electricity in our service territories historically peaks during the summer and winter months, with market prices also generally peaking at those times. Accordingly, FirstEnergy’s annual results of operations and liquidity position may depend disproportionately on its operating performance during the summer and winter. Mild weather conditions may result in lower power sales and consequently lower earnings.
Research and Development

The Utilities, FES, FG, FENOC, ATSI, MAIT and TrAIL participate in the funding of EPRI, which was formed for the purpose of expanding electric R&D under the voluntary participation of the nation’s electric utility industry — public, private and cooperative. Its goal is to mutually benefit utilities and their customers by promoting the development of new and improved technologies to help the utility industry meet present and future electric energy needs in environmentally and economically acceptable ways. EPRI conducts research on all aspects of electric power production and use, including fuels, generation, delivery, efficient management of energy use, environmental effects and energy analysis. The majority of EPRI’s R&D programs and projects are directed toward business solutions and their applications to problems facing the electric utility industry.

FirstEnergy participates in other initiatives with industry R&D consortiums and universities to address technology needs for its various business units. Participation in these consortiums helps the company address research needs in areas such as plant operations and maintenance, major component reliability, environmental controls, advanced energy technologies, and transmission and distribution system infrastructure to improve performance, and develop new technologies for advanced energy and grid applications.

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Executive Officers as of February 20, 2018
Name
 
Age
 
Positions Held During Past Five Years
 
Dates
G. D. Benz
 
58
 
Senior Vice President, Strategy (B)
 
2015-present
 
 
 
 
Vice President, Supply Chain (B)
 
*-2015
 
 
 
 
 
 
 
D. M. Chack
 
67
 
Senior Vice President, Product Development, Marketing and Branding (B)
 
2017-present
 
 
 
 
Senior Vice President, Marketing and Branding (B)
 
2015-2017
 
 
 
 
President, Ohio Operations (B)
 
*-2015
 
 
 
 
Vice President (C)
 
*-2015
 
 
 
 
 
 
 
M. J. Dowling
 
53
 
Senior Vice President, External Affairs (B)
 
*-present
 
 
 
 
 
 
 
B. L. Gaines
 
64
 
Senior Vice President, Corporate Services and Chief Information Officer (B)
 
*-present
 
 
 
 
 
 
 
C. E. Jones
 
62
 
President and Chief Executive Officer (A)(B)
 
2015-present
 
 
 
 
Chief Executive Officer (F)
 
2015-2017
 
 
 
 
President (C)(D)(H)(I)(L)
 
*-2015
 
 
 
 
Executive Vice President & President, FirstEnergy Utilities (A)(B)
 
2014
 
 
 
 
Senior Vice President & President, FirstEnergy Utilities (B)
 
*-2013
 
 
 
 
 
 
 
C. D. Lasky
 
54
 
Senior Vice President, Human Resources (B)
 
2015-present
 
 
 
 
Vice President, Fossil Operations (J)
 
2014-2015
 
 
 
 
Vice President (G)
 
*-2015
 
 
 
 
Vice President, Fossil Operations & Engineering (J)
 
2014
 
 
 
 
Vice President, Fossil Fleet Operations (J)
 
*-2013
 
 
 
 
 
 
 
J. F. Pearson
 
63
 
Executive Vice President and Chief Financial Officer (N)
 
2016-present
 
 
 
 
Executive Vice President and Chief Financial Officer (A)(B)(C)(D)(H)(I)(L)
 
2015-present
 
 
 
 
Executive Vice President and Chief Financial Officer (F)(G)
 
2015-2017
 
 
 
 
Executive Vice President and Chief Financial Officer (E)(J)
 
2015-2016
 
 
 
 
Senior Vice President and Chief Financial Officer (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)
 
*-2015
 
 
 
 
 
 
 
R. P. Reffner
 
67
 
Vice President and General Counsel (N)
 
2016-present
 
 
 
 
Vice President and General Counsel (B)(C)(D)(H)(I)(L)
 
2014-present
 
 
 
 
Vice President and General Counsel (F)(G)
 
2014-2017
 
 
 
 
Vice President and General Counsel (E)(J)
 
2014-2016
 
 
 
 
Vice President, Legal (B)
 
*-2013
 
 
 
 
 
 
 
S. E. Strah
 
54
 
President (G)
 
2017-present
 
 
 
 
President (N)
 
2016-present
 
 
 
 
Senior Vice President & President, FirstEnergy Utilities (B)
 
2015-present
 
 
 
 
President (C)(D)(H)(I)(L)
 
2015-present
 
 
 
 
Vice President, Distribution Support (B)
 
*-2015
 
 
 
 
 
 
 
K. J. Taylor
 
44
 
Vice President and Controller (N)
 
2016-present
 
 
 
 
Vice President, Controller and Chief Accounting Officer (A)(B)
 
2013-present
 
 
 
 
Vice President and Controller (C)(D)(H)(I)(L)
 
2013-present
 
 
 
 
Vice President and Controller (F)(G)
 
2013-2017
 
 
 
 
Vice President and Controller (E)(J)
 
2013-2016
 
 
 
 
Vice President and Assistant Controller (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)
 
*-2013
 
 
 
 
 
 
 
L. L. Vespoli
 
58
 
Executive Vice President, Corporate Strategy, Regulatory Affairs & Chief Legal Officer
(A)(B)(C)(D)(H)(I)(L)(N)
 
2016-present
 
 
 
 
Executive Vice President, Corporate Strategy, Regulatory Affairs & Chief Legal Officer (F)(G)
 
2016-2017
 
 
 
 
Executive Vice President, Corporate Strategy, Regulatory Affairs & Chief Legal Officer (E)(J)
 
2016
 
 
 
 
Executive Vice President, Markets & Chief Legal Officer (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)
 
2014-2016
 
 
 
 
Executive Vice President and General Counsel (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)
 
*-2013
 
 
 
 
 
 
 
E. L. Yeboah-Amankwah
 
40
 
Vice President, Corporate Secretary and Chief Ethics Officer (A)(B)
 
2017-present
 
 
 
 
Vice President, State and Federal Regulatory Legal Affairs (B)
 
2017
 
 
 
 
Vice President and Corporate Secretary (C)(D)(G)(H)(I)(L)(N)
 
2017-present
 
 
 
 
 
 
 
* Indicates position held at least since January 1, 2013
(E) Denotes executive officer of FES
(J) Denotes executive officer of FG
(A) Denotes executive officer of FE
(F) Denotes executive officer of FENOC
(K) Denotes executive officer of OE
(B) Denotes executive officer of FESC
(G) Denotes executive officer of AGC
(L) Denotes executive officer of ATSI
(C) Denotes executive officer of OE, CEI and TE
(H) Denotes executive officer of MP, PE and WP
(M) Denotes executive officer of CEI
(D) Denotes executive officer of ME, PN and Penn
(I) Denotes executive officer of TrAIL and FET
(N) Denotes executive officer of MAIT



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Employees

As of December 31, 2017, FirstEnergy had 15,617 employees located in the United States as follows:
 
Total
Employees
 
Bargaining
Unit
Employees
FESC
4,944

 
893

OE
1,141

 
745

CEI
915

 
594

TE
334

 
244

Penn
185

 
131

JCP&L
1,358

 
1,047

ME
661

 
487

PN
750

 
475

FES
56

 

FG
687

 
499

FENOC
2,328

 
1,028

MP
1,045

 
690

PE
499

 
307

WP
714

 
459

Total
15,617

 
7,599


As of December 31, 2017, the IBEW, the UWUA and the OPEIU unions collectively represented approximately 6,604 of FirstEnergy's employees. There are 22 CBAs between FirstEnergy's subsidiaries and its unions, which have three, four or five year terms. In 2017, certain of FirstEnergy's subsidiaries reached new agreements on CBAs with three different UWUA locals, covering approximately 1,073 employees. Additionally, in 2017, agreements were reached with two IBEW locals, covering approximately 711 employees.
On January 5, 2017, UWUA Local 180, which represents approximately 123 employees in PN, ratified a new agreement that will expire August 31, 2022.
On March 2, 2017, IBEW Local 777, which represents approximately 497 employees in ME, ratified a contract that will expire on April 30, 2022.
On May 18, 2017, IBEW Local 272, which represents approximately 214 employees at the Bruce Mansfield Plant, ratified a new agreement that will expire on February 15, 2020.
On October 10, 2017, UWUA Local 304, which represents approximately 164 employees at the Harrison Plant, ratified a new agreement that will expire March 1, 2022.
On October 27, 2017, UWUA Local 270, which represents approximately 786 employees at CEI, the Perry nuclear plant and the Eastlake synchronous condenser plant, ratified a new agreement that will expire on April 30, 2022.
FirstEnergy Website and Other Social Media Sites and Applications

Each of the registrants’ Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, and FE's proxy statements and amendments to those documents filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through the "Investors" page of FirstEnergy’s Internet website at www.firstenergycorp.com. The public may read and copy any reports or other information that the registrants file with the SEC at the SEC's public reference room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the SEC's public reference room by calling the SEC at 1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services and the website maintained by the SEC at www.sec.gov.

These SEC filings are posted on FirstEnergy's website as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, the registrants routinely post additional important information including press releases, investor presentations and notices of upcoming events, under the "Investors" section of FirstEnergy’s Internet website and recognize FirstEnergy’s Internet website as a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under Regulation FD. Investors may be notified of postings to the website by signing up for email alerts and RSS feeds on the "Investors" page of FirstEnergy's Internet website. FirstEnergy also uses Twitter® and Facebook® as additional channels of distribution to reach public investors and as a supplemental means of disclosing material non-public information for complying with its disclosure obligations under Regulation FD. Information contained on FirstEnergy’s Internet website, posted on FirstEnergy's Facebook® page or disseminated through Twitter®, and any corresponding applications, shall not be deemed incorporated into, or to be part of, this report.

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ITEM 1A.
RISK FACTORS

We operate in a business environment that involves significant risks, many of which are beyond our control. Management of each Registrant regularly evaluates the most significant risks of the Registrants' businesses and reviews those risks with the FE Board of Directors or appropriate Committees of such Board and the FES Board of Directors, respectively. The following risk factors and all other information contained in this report should be considered carefully when evaluating FirstEnergy and FES. These risk factors could affect our financial results and cause such results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Below, we have identified risks we currently consider material. These risks, unless otherwise indicated, are presented on a consolidated basis for FirstEnergy; if and to the extent a deconsolidation occurs with respect to certain FirstEnergy companies, the risks described herein may materially change. Additional information on risk factors is included in “Item 1. Business,” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and in other sections of this Form 10-K that include forward-looking and other statements involving risks and uncertainties that could impact our business and financial results.
Risks Related to the Transition to a Fully Regulated Utility

We Have Taken a Series of Actions to Focus Our Growth on Our Regulated Operations, Particularly Within the Regulated Transmission Segment. Whether This Investment Strategy Will Deliver the Desired Result is Subject to Certain Risks Which Could Adversely Affect Our Results of Operations and Financial Condition in the Future
We focus on capitalizing on investment opportunities available to our regulated operations - particularly within our Regulated Transmission segment - as we focus on delivering enhanced customer service and reliability. The success of these efforts will depend, in part, on successful recovery of our transmission investments. Factors that may affect rate recovery of our transmission investments include: (1) FERC’s timely approval of rates to recover such investments; (2) whether the investments are included in PJM's RTEP; (3) FERC's evolving policies with respect to incentive rates for transmission assets; (4) FERC's evolving policies with respect to the calculation of the base ROE component of transmission rates, as articulated in FERC's Opinion No. 531 and related orders; (5) consideration of the objections of those who oppose such investments and their recovery; and (6) timely development, construction, and operation of the new facilities.
The success of these efforts will also depend, in part, on any future distribution rate cases or other filings seeking cost recovery for distribution system enhancements in the states where our Utilities operate and transmission rate filings at FERC. Any denial of, or delay in, the approval of any future distribution or transmission rate requests could restrict us from fully recovering our cost of service, may impose risks on the Regulated Transmission and Regulated Distribution operations, and could have a material adverse effect on our regulatory strategy and results of operations.
Our efforts also could be impacted by our ability to finance the proposed expansion projects while maintaining adequate liquidity. There can be no assurance that our efforts to reflect a more regulated business profile will deliver the desired result which could adversely affect our future results of operations and financial condition.
Failure to Successfully Implement Strategic Alternatives for the CES Segment to Exit the Competitive Generation Business May Further Negatively and Materially Impact the Future Results of Operations and Financial Condition of FirstEnergy and FES
Weak wholesale energy and capacity markets with significantly low results from recent capacity auctions and anemic demand forecasts have lowered the value of the business and continue to challenge the CES segment, including FES. Consequently, as previously disclosed, FirstEnergy is engaged in a strategic review of its competitive operations including the pending sale of certain AE Supply generation assets, and FES is exploring all alternatives for its generation assets.
These alternatives include, but are not limited to, (i) the sale or deactivation of additional generating units and other assets within CES, including FES, (ii) restructuring FES debt with its creditors, and/or (iii) seeking protection under U.S. bankruptcy laws for FES and FENOC. Management anticipates that the viability of these alternatives will be determined in the near term. Each of FE and FES (together with FENOC) have engaged separate advisors to assist them as they explore these strategic alternatives and other options if these alternatives cannot be implemented. No assurance can be given, however, that these strategic alternatives are viable or will be achieved or sufficiently realized or the time frame in which they may be achieved.
Regardless of the Viability or Success of the Sale of Certain AE Supply Generation Assets and Other Strategic Alternatives for the CES Segment, Certain Events May Significantly Increase Cash Flow and Liquidity Risks, Have a Material Adverse Effect on Results of Operations and the Financial Condition of FE and FES and Cause FES and FENOC, to Take Other Actions, Including Debt Restructuring or Seeking Protection under the U.S. Bankruptcy Laws
Regardless of the viability or success of the sales of CES generation assets and other strategic alternatives for the CES business discussed above, CES, including FES, faces significant cash flow and liquidity risks including, but not limited to the following:
the inability to refinance debt maturities at FES subsidiaries of $515 million and $323 million in 2018 and 2019, respectively, at attractive rates or at all;

27




requests to post additional collateral or accelerate payments, including prepayments to certain trade creditors; and
adverse outcomes in previously disclosed disputes regarding long-term coal and coal transportation contracts.

Even if the alternatives outlined above or any other viable business alternatives are implemented, any one of these events or other further adverse developments in the CES segment could require FES to (i) restructure debt and other financial obligations, or (ii) borrow additional funds from FE under its secured credit facility. In addition, FES and FENOC may determine to seek protection under U.S. bankruptcy laws regardless of the viability of one or more strategic alternatives.

Any such developments could have important consequences, including:

the risk that we may not be able to, or may no longer desire to, complete our planned disposition of our generating assets;
the risk that FirstEnergy could be required to satisfy or otherwise elect to guarantee significant financial obligations of FES or its subsidiaries, which could adversely affect the financial condition and cash flows of FirstEnergy;
the risk that creditors of FES may attempt to assert claims, including those that arise out of litigation or other commercial disputes, against FirstEnergy that may require significant effort and money to defend and could adversely affect the business, financial condition, results of operations and cash flows of FirstEnergy; and
the risk that certain triggering events could constitute events of default under certain of FirstEnergy’s obligations.

Additionally, a deactivation significantly prior to the applicable license expiration date of one or more of NG’s nuclear generating units could have a material adverse effect on FirstEnergy's and/or FES' business, financial condition and results of operations as the NDTs may be insufficient to address all radiological decommissioning costs with respect to the applicable unit, thus requiring financial guarantees or additional contributions, which could be significant. The funds from the NDTs may also be restricted from being used to address other significant costs resulting from a near-term deactivation, such as the costs associated with storing spent nuclear fuel onsite.
Adverse judgments or outcomes in ongoing disputes could result in one or more events of default under various agreements related to the indebtedness of FES. Additionally, although the debt-to-total-capitalization ratio included in FE's credit facility excludes non-cash charges up to $5.5 billion related to asset impairments attributable to the power generation assets owned by FES, AE Supply and each of their subsidiaries, the asset impairments recognized in 2016 fully utilized the $5.5 billion exclusion and charges beyond that amount will negatively impact the debt-to-total-capitalization covenant, which may have a further material adverse effect on the results of operations and financial condition of FE.
There is Substantial Uncertainty as to FES’ Ability to Continue as a Going Concern and Substantial Risk That It May be Necessary for FES and FENOC to Seek Protection Under U.S. Bankruptcy Laws, Which Would Have a Material Adverse Impact on FirstEnergy’s and FES’ Business, Financial Condition, Results of Operations and Cash Flows
Based upon continued significantly low prices in the wholesale energy and capacity markets, weak demand for electricity and anemic demand forecasts along with the inability to obtain legislative or regulatory relief, FES’ cash flow from operations may be insufficient to repay its indebtedness or trade payables in the near- and long-term. FES' near-term obligations and their impact to liquidity raise substantial doubt about FES’ ability to meet its obligations as they come due over the next twelve months and, as such, its ability to continue as a going concern. However, the accompanying financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities that might result from the uncertainty associated with the ability to meet obligations as they come due.
Each of FirstEnergy and FES (together with FENOC) have engaged separate financial and legal advisors to assist with the evaluation of various strategic alternatives and to address the liquidity needs and the current capitalization of FES. Due to FES’ financial condition, there is a substantial risk that it may be necessary for FES and FENOC to seek protection under U.S. bankruptcy laws. An FES bankruptcy proceeding would have a material adverse effect on FES’ business, financial condition, results of operations and cash flows and could have a material adverse effect on FirstEnergy’s business, financial condition, results of operations and cash flows. Management of FirstEnergy and FES would be required to spend a significant amount of time and effort dealing with the bankruptcy proceeding instead of focusing on their business operations. In addition, it is expected that prior to the commencement of any such proceeding, FES will fully draw down its $500 million secured credit facility from FE, which FE would likely fund by borrowing under its bank facility. A bankruptcy proceeding at FES also may make it more difficult to retain, attract or replace management and other key personnel. Moreover, creditors of FES may attempt to assert claims against FirstEnergy that may require significant effort and money to defend. There can be no assurance that FirstEnergy would be successful in defending against any such claims. The costs and the uncertainty of potential liabilities during the pendency of an FES bankruptcy proceeding could have a material and adverse impact on FirstEnergy’s and FES’ business, financial condition, results of operations and cash flows.
FES’ Inability to Satisfy its Financial Obligations Could Require FirstEnergy to Make Substantial Payments in Respect of such Obligations, which Could Adversely Affect the Financial Condition, Cash Flows, and the Ability to Satisfy Obligations of FirstEnergy

FE has provided a revolving credit agreement to FES that permits borrowings of up to $500 million and provides additional credit support to FES of up to $200 million. As part of FirstEnergy’s centralized cash management functions, FES, its subsidiaries and FENOC have the ability to borrow from each other and FE to meet their short-term working capital requirements. In addition, FE

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has guaranteed certain material financial obligations of FES and its subsidiaries. FirstEnergy also could elect to assume or satisfy other material financial obligations of FES and its subsidiaries. It is also possible that creditors of FES may attempt to assert claims against FirstEnergy that may require significant effort and money to defend or could result in losses to FirstEnergy. There can be no assurance that FirstEnergy would be successful in defending against any such claims. Any of these matters could adversely affect the financial condition, cash flows and ability to satisfy obligations of FirstEnergy. In addition, the uncertainty associated with these matters could adversely affect FirstEnergy’s ability to access the capital or credit markets and ability to finance its business.

Adverse Developments Related to the CES Segment Could Trigger Events of Default under Certain FirstEnergy Obligations
FirstEnergy's credit facilities contain various events of default, including with respect to the borrowers or significant subsidiaries (each as defined in the credit agreements), a bankruptcy or insolvency, the failure to pay any principal of or premium or interest on any indebtedness in excess of $100 million, or the failure to satisfy any judgment or order for the payment of money exceeding any applicable insurance coverage by more than $100 million. Although FES and its subsidiaries are not “significant subsidiaries” for these purposes, it is possible that an adverse development related to FES could trigger an event of default under the FirstEnergy credit facilities if creditors of FES asserted successful claims against FE or our significant subsidiaries. Additionally, although the debt-to-total-capitalization ratio covenant included in FirstEnergy's credit facility excludes non-cash charges up to $5.5 billion related to asset impairments attributable to the power generation assets owned by FES, AE Supply and each of their subsidiaries, the asset impairments recognized in 2016 fully utilized the $5.5 billion exclusion and charges beyond that amount will negatively impact the debt-to-total-capitalization covenant. Any development, such as the bankruptcy or insolvency of FirstEnergy subsidiaries, debt acceleration or failures to satisfy judgments, could adversely affect the liquidity of FirstEnergy.
In the Event of a Foreclosure, Liquidation, Bankruptcy or Similar Proceeding Involving FES, FG or NG, the Value of the Collateral Securing the Secured Indebtedness of FES’ Subsidiaries May Not be Sufficient to Ensure Repayment of Such Indebtedness and, in the Case of a Bankruptcy Proceeding, the Ability of Holders of Such Indebtedness, Including FE, to Realize Any such Value May be Delayed or Otherwise Limited
FG and NG have secured pollution control notes outstanding as of December 31, 2017 of $612.2 million (FG - $327.6 million of FMBs; NG - $284.6 million of FMBs) and secured obligations supporting FES’ $500 million revolving line of credit and $200 million additional credit support with FE (FG - $250 million of FMBs; NG - $450 million of FMBs). In the event of a foreclosure, liquidation, bankruptcy or similar proceeding affecting FES, FG or NG or any of their respective properties or assets, the value of the collateral securing such indebtedness or the net proceeds from any sale or liquidation of such collateral, as applicable, may not be sufficient to pay the obligations under such secured indebtedness. If the value of the collateral or the net proceeds of any sale of such collateral, as applicable, are not sufficient to repay all amounts due with respect to such secured indebtedness, the holders of the secured indebtedness would have an unsecured claim for the deficiency in value or proceeds against the applicable obligors alongside all other unsecured creditors of such obligor. None of FG, NG or FES can assure holders of their respective secured debt that, if a sale process were to be pursued, the collateral will be saleable or, if saleable, that there will not be substantial delays in its liquidation due to, among other things, the need for regulatory authorization from the FERC, NRC or other governmental authorities, as applicable.
Additionally, in the context of a bankruptcy case by or against FES, FG or NG, the holders of the secured indebtedness may not be able or entitled to receive payment of interest, fees (including attorney’s fees), costs or charges related to such secured obligations, and may be required to repay any such amounts received by such holders during such bankruptcy case.
The value of the collateral securing FG’s and NG’s secured obligations is subject to fluctuation and will depend on market and other economic conditions, including the availability of any suitable buyers for the collateral, which could be impacted by the risks and costs associated with operating nuclear generation facilities in the case of NG’s properties and the risks and costs of operating coal and other fossil-fueled generation facilities in the case of FG’s properties, including, in each case, complying with federal, state and local statutes and regulations associated with public health and safety and the environment.
FirstEnergy and FES May Not Be Successful in Pursuing and/or Consummating Sales of Generating Assets, Which Could Result in Further Substantial Write-Downs and Impairments of Assets and Have a Material Adverse Effect on the Results of Operations and Financial Condition of FirstEnergy and FES
Since beginning their strategic review of the CES segment, FirstEnergy and FES have been pursuing the sale of certain generating and other assets. Any such sale may be difficult to implement due to current and anticipated future market conditions and the attractiveness of nuclear and coal facilities to prospective purchasers. Additionally, because of the current financial condition of FES, those sales may be more difficult to execute at market values or at all.
In this regard, AE Supply and AGC entered into an asset purchase agreement with a subsidiary of LS Power, as amended and restated in August 2017, to sell four natural gas generating plants, AE Supply's interest in the Buchanan Generating facility and approximately 59% of AGC’s interest in Bath County (1,615 MWs of combined capacity), each component of which may close separately, for an aggregate all-cash purchase price of $825 million, subject to adjustments.

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While the sale of the four natural gas generating plants was completed on December 13, 2017, the sale of AE Supply’s interest in the Buchanan Generating facility and AGC’s interest in Bath County remain pending and are expected to close in the first half of 2018, subject to, in each case, various customary and other closing conditions including, without limitation, receipt of regulatory approvals.
If the above sales or any others by AE Supply or FES are not achieved or realized, AE Supply and FES may take further substantial write-downs and impairments of assets, which could have a material adverse effect on the results of operations and financial condition of FirstEnergy and FES and put additional pressure on the success of other strategic alternatives for remaining generation assets at FES and AE Supply. There can be no assurance that all closing conditions will be satisfied or that such sales will be consummated.
Certain FirstEnergy Companies May Not be Able to Meet Their Obligations to or on behalf of Other FirstEnergy Companies or Their Affiliates Which Could Have a Material Adverse Effect on the Results of Operations, Financial Condition or Liquidity of one or more FirstEnergy Entities, Including Additional Significant Exposure in the Event of a Bankruptcy Proceeding by FES and/or FENOC

Certain of the FirstEnergy companies have obligations to other FirstEnergy companies pursuant to transactions involving credit, energy, coal, other commodities, services and hedging transactions. If one FirstEnergy entity failed to perform under any of these arrangements, other FirstEnergy entities could incur losses. Their results of operations, financial position, or liquidity could be adversely affected, and could result in the nondefaulting FirstEnergy entity being unable to meet its obligations to unrelated third parties. Certain FirstEnergy companies also provide guarantees to third party creditors on behalf of other FirstEnergy affiliate companies under transactions of the type described above, legal settlements or under financing transactions. Any failure to perform under such guarantee by such FirstEnergy guarantor company or under the underlying transaction by the FirstEnergy company on whose behalf the guarantee was issued could have similar adverse impacts on one or both FirstEnergy companies or their affiliates.

FES provides a parental support agreement to NG of up to $400 million related to certain operating expenses and requirements. The NRC typically relies on such parental support agreements to provide additional assurance that U.S. merchant nuclear plants, including NG’s nuclear units, have the necessary financial resources to maintain safe operations, particularly in the event of extraordinary circumstances. If FES is called upon by NG to perform under this arrangement, FES’ results of operations, financial position, and liquidity could be adversely affected, and could result in FES being unable to meet its obligations to unrelated third parties.
In addition, there are significant commercial and other relationships among FE, FES and other FE subsidiaries, including, but not limited to, AE Supply and FENOC. In the event FES seeks protection under U.S. bankruptcy laws, it is expected FENOC will similarly seek protection under U.S. bankruptcy laws. These relationships include a shared services agreement, cash management, intercompany loans, tax sharing and energy-related purchases and sales, among others, which would be subject to review and possible challenge in the event of an FES or FENOC bankruptcy proceeding. FirstEnergy is unable to estimate the outcome of such challenges or other claims arising out of an FES or FENOC bankruptcy proceeding, any resulting material losses, obligations or other liabilities of FirstEnergy or their possible material adverse effect on the business, results of operations and financial condition of FirstEnergy, including, but not limited to, AE Supply.
FES and FG are exposed to losses under the sale and leaseback arrangement for Unit 1 at the Bruce Mansfield plant upon the occurrence of certain contingent events that could render that facility worthless such as a casualty event. FES and FG have a maximum exposure to loss under those provisions of approximately $1.1 billion.
On the morning of January 10, 2018, Bruce Mansfield plant personnel were in the process of shutting down Unit 1 for a maintenance outage when an equipment failure resulted in an unplanned outage for Unit 2 that led to the loss of plant power. Later that morning, a fire damaged the scrubber, stack and other plant property and systems associated with Units 1 and 2. Evaluation of the extent of the damage, which may be significant, to the scrubber, stack and other plant property and systems associated with Units 1 and 2, and whether it may trigger a loss under the sale and leaseback arrangement, is underway and is expected to take several weeks.
As part of AE Supply’s recent sale of gas generation assets to a subsidiary of LS Power, FE provided two limited three-year guarantees totaling $555 million of certain obligations of AE Supply and AGC arising under the purchase agreement. Liabilities incurred under these guarantees could have an adverse impact on FE.
Risks Related to the CES Segment

Continued Low Prices in the Wholesale Energy and Capacity Markets May Further Negatively and Materially Impact the Future Results of Operations and Financial Condition of FirstEnergy and FES Including the Ongoing Strategic Review of Competitive Operations

Long-term low prices in the wholesale energy and capacity markets continue to challenge the coal and nuclear baseload generating units within the CES business segment, including those of FES. The continued weakness of these markets may further negatively and materially impact the future results of operations and financial condition of FirstEnergy and FES and may limit the ability of FES to sell these units to third parties.

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FE does not intend to infuse additional equity into CES and only expects to continue to support CES, including FES, as necessary to maintain safe operations and to preserve the fleet as it pursues strategic alternatives with respect to CES. However, FES has liquidity support through the secured credit facility entered into between FES and FE in December 2016 and an unregulated companies’ money pool, through which FE expects to provide ongoing liquidity to FES and its subsidiaries through March 2018. AE Supply has access to a separate unregulated companies' money pool. No assurance can be given, however, that such expectations will not change or that the strategic alternatives for CES are viable or will be achieved or sufficiently realized. If options that retain the current fleet cannot be implemented or can only be implemented for a portion of the CES fleet, we may consider other options longer term, such as the sale or deactivation of additional generating units within CES, including FES, which may have a further material adverse effect on the results of operations and financial condition of FirstEnergy and FES.

FES Has a Significant Amount of Indebtedness, Which Could Adversely Affect FirstEnergy’s and FES’ Cash Flow and Liquidity and the Ability of FES and its Subsidiaries to Fulfill their Obligations, Which Could Cause FES to Seek Protection under U.S. Bankruptcy Laws

FES and its subsidiaries have a significant amount of indebtedness, some of which is secured. Specifically, as of December 31, 2017, $2.8 billion of outstanding long-term debt, of which approximately $610 million is secured and approximately $2.2 billion is unsecured.

As a result of this debt, a substantial portion of cash flow from the operations of FES must be used to make payments on this debt, including the payment of principal and interest. Furthermore, since a material percentage of the FES assets are used to secure this debt, and much of those assets have been substantially written down, there is little or no collateral available for future secured debt or credit support, which reduces flexibility in dealing with future liquidity needs or financial difficulties. This high level of indebtedness and related collateral pledges could have other adverse consequences to FES, including:
difficulty satisfying debt service and other obligations at FES and/or its individual subsidiaries;
the unlikelihood of FG and NG being able to refinance debt maturities of $515 million and $323 million in 2018 and 2019, respectively;
additional postings of collateral or acceleration of payments;
increasing the vulnerability of the business of FES to adverse industry and economic conditions;
reducing the availability of FES cash flow to fund other corporate purposes; and
reducing the ability of FES to enter into transactions with counterparties due to demands for additional collateral or credit support due to FES' creditworthiness.

If market conditions in the wholesale energy and capacity markets continue to be weak and the strategic alternatives described above are not viable, achieved or sufficiently realized, then the cash flows of FES may not be sufficient to fund debt service obligations, including the repayment at maturity of all the outstanding debt as it becomes due. In that event, FES may not be able to borrow money, sell assets, raise equity or otherwise raise funds on acceptable terms or at all to refinance its debt as it becomes due, which could have a material adverse effect on the results of operations, financial condition and liquidity of FirstEnergy and FES, result in one or more events of default being declared under various agreements related to the indebtedness of FES and cause FES to seek protection under U.S. bankruptcy laws. In the event FES seeks such protection, it is likely FENOC will similarly seek protection under U.S. bankruptcy laws.

Additionally, if any potential defaults at FES are not resolved through waivers or otherwise cured, lenders could accelerate the maturity of the applicable debt which may, among other things, result in cross defaults of other FES debt obligations. These defaults would have a material adverse effect on FirstEnergy’s and FES' business, financial condition, results of operations and liquidity.

Disruptions in Fuel Supplies and Changes in Fuel Transportation Needs Could Adversely Affect Relationships With Suppliers, the Ability to Operate Generation Facilities or Lead to Business Disputes and Material Judgments, Any of Which May Adversely Impact Financial Results, and in the Case of a Certain Fuel Transportation Contract, an Adverse Resolution Could Cause FES to Seek Bankruptcy Protection and Result in One or More Events of Default Under Various Agreements Related to the Indebtedness of FES

CES purchases fuel from a number of suppliers. The lack of availability of fuel at expected prices, or a disruption in the delivery of fuel which exceeds the duration of our on-site fuel inventories, including disruptions as a result of weather, increased transportation costs or other difficulties, labor relations or environmental or other regulations affecting fuel suppliers, could cause an adverse impact on the ability to operate CES' generating facilities, possibly resulting in lower sales and/or higher costs and thereby adversely affect results of operations of FirstEnergy and FES.

Operation of CES' coal-fired generation facilities is highly dependent on its ability to procure coal. CES has long-term contracts in place for a majority of its coal supply and transportation needs, one of which runs through 2028 and certain of which relate to deactivated plants. For example, AE Supply and FG have asserted force majeure defenses for delivery shortfalls under certain of these agreements relating to our deactivated plants. One such agreement which is currently in arbitration relates to the transportation of an aggregate of a minimum of 2.5 million tons of coal annually through 2025 to certain operating and deactivated coal-fired power

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plants owned by FG. In addition, in one coal supply agreement, AE Supply has also asserted termination rights effective in 2015 and is in litigation with the counterparty.

No assurance can be provided that negotiations with counterparties, or any litigation or arbitration, will be favorably resolved. An adverse resolution of any of these material matters could have a material adverse impact on the financial condition and results of operations of FirstEnergy and FES, and in the case of the arbitration related to the fuel transportation contract discussed above, an adverse resolution could require FES to (i) restructure debt and other financial obligations, (ii) borrow additional funds from FE under its secured credit facility, (iii) sell additional assets or deactivate additional plants and/or (iv) seek protection under U.S. bankruptcy laws, which in turn would result in one or more events of default under various agreements related to the indebtedness of FES. In the event FES seeks such protection, it is expected FENOC will similarly seek protection under U.S. bankruptcy laws.

Continued Pressure on Commodity Prices Including, but Not Limited to, Fuel for Generation Facilities, Could Adversely Affect Profit Margins

During the period of FirstEnergy’s transition to a fully regulated company away from commodity exposed generation, CES continues to purchase and sell electricity in the competitive retail and wholesale markets. Increases in the costs of fuel for generation facilities (particularly coal, uranium and natural gas) may affect CES’ profit margins. Competition and changes in the short or long-term market price of electricity, which are affected by changes in other commodity costs and other factors including, but not limited to, weather, energy efficiency mandates, DR initiatives and deactivations and retirements at power generation facilities, may impact the results of operations and financial position of FirstEnergy and FES by decreasing sales margins or increasing the amount paid to purchase power to satisfy sales obligations in the states in which CES does business. CES is exposed to risk from the volatility of the market price of natural gas. Its ability to sell at a profit is highly dependent on the price of natural gas. With low natural gas prices, other market participants that utilize natural gas-fired generation will be able to offer electricity at increasingly competitive prices, so the margins CES realizes from sales will be lower and, on occasion, CES may curtail or cease operation of marginal plants. The availability of natural gas and issues related to its accessibility may have a long-term material impact on the price of natural gas.

CES Is Exposed to Price Risks Associated With Marketing and Selling Products in the Power Markets That It Does Not Always Completely Hedge Against

CES purchases and sells power at the wholesale level under market-based rate tariffs authorized by FERC, and also enters into agreements to sell available energy and capacity from its generation assets. If CES is unable to deliver firm capacity and energy under these agreements, it may be required to pay damages, including significant penalties under PJM's Capacity Performance market reform. These damages would generally be based on the difference between the market price to acquire replacement capacity or energy and the contract price of the undelivered capacity or energy. Depending on price volatility in the wholesale energy markets, such damages and penalties could be significant. A single outage could result in penalties that exceed capacity revenues for a given unit in a given year. Extreme weather conditions, unplanned power plant outages, transmission disruptions, and other factors could affect CES' ability to meet its obligations, or cause increases in the market price of replacement capacity and energy.

CES attempts to mitigate risks associated with satisfying its contractual power sales arrangements by reserving generation capacity to deliver electricity to satisfy its net firm sales contracts and, when necessary, by purchasing firm transmission service. CES also routinely enters into contracts, such as fuel and power purchase and sale commitments, to hedge exposure to fuel requirements and other energy-related commodities. CES may not, however, hedge the entire exposure of its operations from commodity price volatility. To the extent CES does not hedge against commodity price volatility, the results of operations and financial position of FirstEnergy and FES could be negatively affected. In addition, these risk management related contracts could require the posting of additional collateral in the event market prices or market conditions change or FES or AE Supply's credit ratings are further downgraded.

Nuclear Generation Involves Risks that Include Uncertainties Relating to Health and Safety, the Environment, Additional Capital Costs, the Adequacy of Insurance Coverage, NRC Actions and Nuclear Plant Decommissioning, Which Could Have a Material Adverse Effect on the Business, Results of Operations and Financial Condition of FirstEnergy and FES

FES is subject to the risks of nuclear generation, including but not limited to the following:
the potential harmful effects on the environment, human health and safety, including loss of life, resulting from unplanned radiological releases associated with the operation of FES' nuclear facilities and the storage, handling and disposal of radioactive materials;
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with FES' nuclear operations, including any incidents of unplanned radiological release, or those of others in the United States;
uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and
uncertainties with respect to the technological and financial aspects of spent fuel storage and decommissioning nuclear plants, including but not limited to, waste disposal at the end of their licensed operation and increases in minimum funding requirements or costs of decommissioning.


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The NRC has broad authority under federal law to impose licensing, security and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down a unit, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants, including those of FES. Also, a serious nuclear incident at one of FES' nuclear facilities or a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit. Any one of these risks relating to FES' nuclear generation could have a material adverse effect on the business, results of operations and financial condition of FirstEnergy and FES.
There Are Uncertainties Relating to Participation in RTOs Which Could Result In Significant Additional Fees and Increased Costs to Participate in an RTO, Limit the Recovery of Costs from Retail Customers and Have an Adverse Effect on the Results of Operations and Cash Flows and Financial Condition of FirstEnergy and FES
RTO rules could affect the ability to sell energy and capacity produced by CES' generating facilities to users in certain markets. The rules governing the various regional power markets may change from time to time, which could affect its costs or revenues. In some cases, these changes are contrary to its interests and adverse to its financial returns. The prices in day-ahead and real-time energy markets and RTO capacity markets have been volatile and RTO rules may contribute to this volatility.
All of CES' generating assets currently participate in PJM, which conducts RPM auctions for capacity on an annual planning year basis. The prices CES can charge for its capacity are determined by the results of the PJM auctions, which are impacted by the supply and demand of capacity resources and load within PJM and also may be impacted by transmission system constraints and PJM rules relating to bidding for DR, energy efficiency resources, and imports, among others. Auction prices could fluctuate substantially over relatively short periods of time. To the extent PJM's Capacity Performance market reforms do not work as intended, energy and capacity market prices may remain volatile and low. CES cannot predict the outcome of future auctions, but if the auction prices are sustained at low levels, the results of operations, financial condition and cash flows of FirstEnergy and FES could be adversely impacted.
CES incurs fees and costs to participate in RTOs. Administrative costs imposed by RTOs, including the cost of administering energy markets, may increase. To the degree CES incurs significant additional fees and increased costs to participate in an RTO, and is limited with respect to recovery of such costs from retail customers, the results of operations and cash flows of FirstEnergy and FES could be significantly impacted.
As a member of an RTO, CES is subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in that RTO’s market and those associated with complaint cases filed against the RTO that may seek refunds of revenues previously earned by its members.
Risks Related to Business Operations Generally

We Are Subject to Risks Arising from the Operation of Our Power Plants and Transmission and Distribution Equipment Which Could Reduce Revenues, Increase Expenses and Have a Material Adverse Effect on our Business, Financial Condition and Results of Operations
Operation of generation, transmission and distribution facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, human error in operations or maintenance, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental requirements and governmental interventions, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.
Operation of our power plants below expected capacity could result in lost revenues and increased expenses, including higher operation and maintenance costs, purchased power costs and capital requirements. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses or may require us to incur significant costs as a result of operating our higher cost units or obtaining replacement power from third parties in the open market to satisfy our sales obligations. Moreover, if we were unable to perform under contractual obligations, including, but not limited to, our coal and coal transportation contracts, penalties or liability for damages could result, which could have a material adverse effect on our business, financial condition and results of operations.
Failure to Provide Safe and Reliable Service and Equipment Could Result in Serious Injury or Loss of Life That May Harm Our Business Reputation and Adversely Affect our Operating Results
We are obligated to provide safe and reliable service and equipment in our franchised service territories. Meeting this commitment requires the expenditure of significant capital resources. However, our employees, contractors and the general public may be

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exposed to dangerous environments due to the nature of our operations. Failure to provide safe and reliable service and equipment due to a number of factors, including equipment failure, accidents and weather, could result in serious injury or loss of life that may harm our business reputation and adversely affect our operating results through reduced revenues and increased capital and operating costs and the imposition of penalties/fines or other adverse regulatory outcomes.
The Use of Non-Derivative and Derivative Contracts by Us to Mitigate Risks Could Result in Financial Losses That May Negatively Impact Our Financial Results
We use a variety of non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. Also, we could recognize financial losses as a result of volatility in the market value of these contracts if a counterparty fails to perform or if there is limited liquidity of these contracts in the market.
Financial Derivatives Reforms Could Increase Our Liquidity Needs and Collateral Costs and Impose Additional Regulatory Burdens
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) was enacted into law in July 2010 with the primary objective of increasing oversight of the United States financial system, including the regulation of most financial transactions, swaps and derivatives. Dodd-Frank requires CFTC and SEC rulemaking to implement such provisions. Although the CFTC and the SEC have completed certain of their rulemaking, other rulemaking remains.
We rely on the OTC derivative markets as part of our program to hedge the price risk associated with our power portfolio. As a qualified end-user, we are required to comply with regulatory obligations under Dodd-Frank, which includes record-keeping, reporting requirements and the clearing of some transactions that we would otherwise enter into over-the-counter and the posting of margin. Also, the total burden that the rules could impose on all market participants could cause liquidity in the bilateral OTC swap market to decrease. These rules could impede our ability to meet our hedge targets in a cost-effective manner. FirstEnergy cannot predict the future impact Dodd-Frank rulemaking will have on its results of operations, cash flows or financial position.
Our Risk Management Policies Relating to Energy and Fuel Prices, and Counterparty Credit, Are by Their Very Nature Subject to Uncertainties, and We Could Suffer Economic Losses Resulting in an Adverse Effect on Results of Operations Despite Our Efforts to Manage and Mitigate Our Risks
We attempt to mitigate the market risk inherent in our energy, fuel and debt positions. Procedures have been implemented to enhance and monitor compliance with our risk management policies, including validation of transaction and market prices, verification of risk and transaction limits, sensitivity analysis and daily portfolio reporting of various risk measurement metrics. Nonetheless, we cannot economically hedge all of our exposure in these areas and our risk management program may not operate as planned. For example, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions reflected in our analyses. Also, our power plants might not produce the expected amount of power during a given day or time period due to weather conditions, technical problems or other unanticipated events, which could require us to make energy purchases at higher prices than the prices under our energy supply contracts, and also to pay significant penalties under PJM's Capacity Performance market reforms. In addition, the amount of fuel required for our power plants during a given day or time period could be more than expected, which could require us to buy additional fuel at prices less favorable than the prices under our fuel contracts. As a result, actual events may lead to greater losses or costs than our risk management positions were intended to hedge.
Our risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as the creditworthiness of counterparties, future market prices and demand for power and other energy-related commodities. These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be adversely affected if the judgments and assumptions underlying those calculations prove to be inaccurate.
The Outcome of Litigation, Arbitration, Mediation, and Similar Proceedings Involving Our Business, or That of One or More of Our Operating Subsidiaries, Including Certain Fuel and Fuel Transportation Contracts, is Unpredictable and an Adverse Decision in Any Material Proceeding Could Have a Material Adverse Effect on Our Financial Condition and Results of Operations, and in the Case of Proceedings Related to a Certain Fuel Transportation Contract, an Adverse Decision Could Cause FES to Seek Bankruptcy Protection and Result in One or More Events of Default Under Various Agreements Related to the Indebtedness of FES
We are involved in a number of litigation, arbitration, mediation, and similar proceedings including, but not limited to, such proceedings relating to certain fuel and fuel transportation contracts. These and other matters may divert financial and management resources that would otherwise be used to benefit our operations. Further, no assurances can be given that the resolution of these matters will be favorable to us. If certain matters were ultimately resolved unfavorably to us, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted, and in the case of proceedings related to a certain coal transportation contract, such an unfavorable result could require FES to seek protection under U.S. bankruptcy laws, which in turn

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would result in one or more events of default under various agreements related to the indebtedness of FES. In the event FES seeks such protection, it is expected FENOC will similarly seek protection under U.S. bankruptcy laws.
In addition, we are sometimes subject to investigations and inquiries by various state and federal regulators due to the heavily regulated nature of our industry. Any material inquiry or investigation could potentially result in an adverse ruling against us, which could have a material adverse impact on our financial condition and operating results.
We Have a Significant Percentage of Coal-Fired Generation Capacity Which Exposes Us to Risk from Regulations Relating to Coal, GHGs and CCRs
Approximately 58% of FirstEnergy's generation fleet capacity is coal-fired, totaling 9,406 MWs, of which 6,313 MWs is within the CES segment. Historically, coal-fired generating plants have greater exposure to the costs of complying with federal, state and local environmental statutes, rules and regulations relating to air emissions, including GHGs, and CCR disposal, than other types of electric generation facilities. These legal requirements and any future initiatives could impose substantial additional costs and, in the case of GHG requirements, could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities and could require our coal-fired generation plants to curtail generation or cease to generate. Failure to comply with any such existing or future legal requirements may also result in the assessment of fines and penalties. Significant resources also may be expended to defend against allegations of violations of any such requirements.
Capital Market Performance and Other Changes May Decrease the Value of Pension Fund Assets and Other Trust Funds, Which Could Require Significant Additional Funding and Negatively Impact our Results of Operations and Financial Condition
Our financial statements reflect the values of the assets held in trust to satisfy our obligations to decommission our nuclear generating facilities and under pension and other postemployment benefit plans. Certain of the assets held in these trusts do not have readily determinable market values. Changes in the estimates and assumptions inherent in the value of these assets could affect the value of the trusts. If the value of the assets held by the trusts declines by a material amount, our funding obligation to the trusts could materially increase. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. Forecasting investment earnings and costs to decommission FirstEnergy's nuclear generating facilities, to pay future pension and other obligations, requires significant judgment and actual results may differ significantly from current estimates. Capital market conditions that generate investment losses or that negatively impact the discount rate and increase the present value of liabilities may have significant impacts on the value of the decommissioning, pension and other trust funds, which could require significant additional funding and negatively impact our results of operations and financial position.
We Could be Subject to Higher Costs and/or Penalties Related to Mandatory Reliability Standards Set by NERC/FERC or Changes in the Rules of Organized Markets
Owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by NERC and approved by FERC. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. NERC, RFC and FERC can be expected to continue to refine existing reliability standards as well as develop and adopt new reliability standards. Compliance with modified or new reliability standards may subject us to higher operating costs and/or increased capital expenditures. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties. FERC has authority to impose penalties up to and including $1 million per day for failure to comply with these mandatory electric reliability standards.
In addition to direct regulation by FERC, we are also subject to rules and terms of participation imposed and administered by various RTOs and ISOs. Although these entities are themselves ultimately regulated by FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, the independent market monitors of ISOs and RTOs may impose bidding and scheduling rules to curb the perceived potential for exercise of market power and to ensure the markets function appropriately. Such actions may materially affect our ability to sell, and the price we receive for, our energy and capacity. In addition, PJM may direct our transmission-owning affiliates to build new transmission facilities to meet PJM's reliability requirements or to provide new or expanded transmission service under the PJM Tariff.
We incur fees and costs to participate in RTOs. Administrative costs imposed by RTOs, including the cost of administering energy markets, may increase. To the degree we incur significant additional fees and increased costs to participate in an RTO, and are limited with respect to recovery of such costs from retail customers, our results of operations and cash flows could be significantly impacted.
We may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. We may be required to expand our transmission system according to decisions made by an RTO rather than our own internal planning processes. Various proposals and proceedings before FERC may cause transmission rates to change from time to time. In addition, RTOs have been developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial impact on us.

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As a member of an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in that RTO’s market and those associated with complaint cases filed against the RTO that may seek refunds of revenues previously earned by its members.
We Rely on Transmission and Distribution Assets That We Do Not Own or Control to Deliver Our Wholesale Electricity. If Transmission is Disrupted, Including Our Own Transmission, Not Operated Efficiently, or if Capacity is Inadequate, Our Ability to Sell and Deliver Power May Be Adversely Affected
We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity we sell. If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by ISOs and RTOs, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be adversely affected, or we may be unable to sell products on the most favorable terms. In addition, in certain of the markets in which we operate, we may be required to pay for congestion costs if we schedule delivery of power between congestion zones during periods of high demand. If we are unable to hedge or recover such congestion costs in retail rates, our financial results could be adversely affected.
Demand for electricity within our Utilities’ service areas could stress available transmission capacity requiring alternative routing or curtailing electricity usage that may increase operating costs or reduce revenues with adverse impacts to our results of operations. In addition, as with all utilities, potential concerns over transmission capacity could result in PJM or FERC requiring us to upgrade or expand our transmission system, requiring additional capital expenditures that we may be unable to recover fully or at all.
FERC requires wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, it is possible that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electricity as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether ISOs or RTOs in applicable markets will operate the transmission networks, and provide related services, efficiently.
Temperature Variations as well as Weather Conditions or other Natural Disasters Could Have an Adverse Impact on Our Results of Operations and Financial Condition and Demand Significantly Below or Above Our Forecasts Could Adversely Affect Our Energy Margins and Have an Adverse Effect on our Financial Condition and Results of Operations
Weather conditions directly influence the demand for electric power. Demand for power generally peaks during the summer and winter months, with market prices also typically peaking at that time. Overall operating results may fluctuate based on weather conditions. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, ice or snowstorms, or droughts or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period and could have an adverse effect on our financial condition and results of operations.
Customer demand could change as a result of severe weather conditions or other circumstances over which we have no control. We satisfy our electricity supply obligations through a portfolio approach of providing electricity from our generation assets, contractual relationships and market purchases. A significant increase in demand could adversely affect our energy margins if we are required to provide the energy supply to fulfill this increased demand at fixed rates, which we expect would remain below the wholesale prices at which we would have to purchase the additional supply if needed or, if we had available capacity, the prices at which we could otherwise sell the additional supply. A significant decrease in demand, resulting from factors including but not limited to increased customer shopping, more stringent energy efficiency mandates and increased DR initiatives could cause a decrease in the market price of power. Accordingly, any significant change in demand could have a material adverse effect on our results of operations and financial position.
We Are Subject to Financial Performance Risks Related to Regional and General Economic Cycles and also Related to Heavy Industries such as Shale Gas, Automotive and Steel
Our business follows economic cycles. Economic conditions impact the demand for electricity and declines in the demand for electricity will reduce our revenues. The regional economy in which our Utilities operate is influenced by conditions in industries in our business territories, e.g. shale gas, automotive, chemical, steel and other heavy industries, and as these conditions change, our revenues will be impacted. Additionally, the primary market areas of our CES segment overlap, to a large degree, with our Utilities' territories and hence its revenues are substantially impacted by the same economic conditions, such as changes in industrial demand.

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We Face Certain Human Resource Risks Associated with Potential Labor Disruptions and/or With the Availability of Trained and Qualified Labor to Meet Our Future Staffing Requirements
We are continually challenged to find ways to balance the retention of our aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Additionally, a significant number of our physical workforce are represented by unions. While we believe that our relations with our employees are generally fair, we cannot provide assurances that the company will be completely free of labor disruptions such as work stoppages, work slowdowns, union organizing campaigns, strikes, lockouts or that any labor disruption will be favorably resolved. Mitigating these risks could require additional financial commitments and the failure to prevent labor disruptions and retain and/or attract trained and qualified labor could have an adverse effect on our business.
Significant Increases in Our Operation and Maintenance Expenses, Including Our Health Care and Pension Costs, Could Adversely Affect Our Future Earnings and Liquidity
We continually focus on limiting, and reducing where possible, our operation and maintenance expenses. However, we expect to continue to face increased cost pressures related to operation and maintenance expenses, including in the areas of health care and pension costs. We have experienced health care cost inflation in recent years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken requiring employees and retirees to bear a higher portion of the costs of their health care benefits. The measurement of our expected future health care and pension obligations and costs is highly dependent on a variety of assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, discount rates, health care cost trends, benefit design changes, salary increases, the demographics of plan participants and regulatory requirements. While we anticipate that our operation and maintenance expenses will continue to increase, if actual results differ materially from our assumptions, our costs could be significantly higher than expected which could adversely affect our future earnings and liquidity.
Our Results May be Adversely Affected by the Volatility in Pension and OPEB Expenses
FirstEnergy recognizes in income the change in the fair value of plan assets and net actuarial gains and losses for its defined Pension and OPEB plans. This adjustment is recognized in the fourth quarter of each year and whenever a plan is determined to qualify for a remeasurement, which could result in greater volatility in pension and OPEB expenses and may materially impact our results of operations.
FirstEnergy recognizes as a pension and OPEB mark-to-market adjustment the change in the fair value of plan assets and net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement.
Cyber-Attacks, Data Security Breaches and Other Disruptions to Our Information Technology Systems Could Compromise Our Business Operations, Critical and Proprietary Information and Employee and Customer Data, Which Could Have a Material Adverse Effect on Our Business, Financial Condition and Reputation
In the ordinary course of our business, we depend on information technology systems that utilize sophisticated operational systems and network infrastructure to run all facets of our generation, transmission and distribution services. Additionally, we store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers, suppliers, business partners and other individuals in our data centers and on our networks. The secure maintenance of information and information technology systems is critical to our operations.
Over the last several years, there has been an increase in the frequency of cyber-attacks by terrorists, hackers, international activist organizations, countries and individuals. These and other unauthorized parties may attempt to gain access to our network systems or facilities, or those of third parties with whom we do business in many ways, including directly through our network infrastructure or through fraud, trickery, or other forms of deceiving our employees, contractors and temporary staff. Additionally, our information and information technology systems may be increasingly vulnerable to data security breaches, damage and/or interruption due to viruses, human error, malfeasance, faulty password management or other malfunctions and disruptions. Further, hardware, software, or applications we develop or procure from third parties may contain defects in design or manufacture or other problems that could unexpectedly compromise information and/or security.
Despite security measures and safeguards we have employed, including certain measures implemented pursuant to mandatory NERC Critical Infrastructure Protection standards, our infrastructure may be increasingly vulnerable to such attacks as a result of the rapidly evolving and increasingly sophisticated means by which attempts to defeat our security measures and gain access to our information technology systems may be made. Also, we may be at an increased risk of a cyber-attack and/or data security breach due to the nature of our business.
Any such cyber-attack, data security breach, damage, interruption and/or defect could: (i) disable our generation, transmission (including our interconnected regional transmission grid) and/or distribution services for a significant period of time; (ii) delay development and construction of new facilities or capital improvement projects; (iii) adversely affect our customer operations; (iv)

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corrupt data; and/or (v) result in unauthorized access to the information stored in our data centers and on our networks, including, company proprietary information, supplier information, employee data, and personal customer data, causing the information to be publicly disclosed, lost or stolen or result in incidents that could result in economic loss and liability and harmful effects on the environment and human health, including loss of life. Additionally, because our generation, transmission and distribution services are part of an interconnected system, disruption caused by a cybersecurity incident at another utility, electric generator, RTO, or commodity supplier could also adversely affect our operations.
Although we maintain cyber insurance and property and casualty insurance, there can be no assurance that liabilities or losses we may incur will be covered under such policies or that the amount of insurance will be adequate. Further, as cyber threats become more difficult to detect and successfully defend against, there can be no assurance that we can implement adequate preventive measures, accurately assess the likelihood of a cyber-incident or quantify potential liabilities or losses. Also, we may not discover any data security breach and loss of information for a significant period of time after the data security breach occurs. For all of these reasons, any such cyber incident could result in significant lost revenue, the inability to conduct critical business functions and serve customers for a significant period of time, the use of significant management resources, legal claims or proceedings, regulatory penalties, increased regulation, increased capital costs, increased protection costs for enhanced cyber security systems or personnel, damage to our reputation and/or the rendering of our internal controls ineffective, all of which could materially adversely affect our business and financial condition.
Physical Acts of War, Terrorism or Other Attacks on any of Our Facilities or Other Infrastructure Could Have an Adverse Effect on Our Business, Results of Operations and Financial Condition
As a result of the continued threat of physical acts of war, terrorism, or other attacks in the United States, our electric generation, fuel storage, transmission and distribution facilities and other infrastructure, including nuclear and other power plants, transformer and high voltage lines and substations, or the facilities or other infrastructure of an interconnected company, could be direct targets of, or indirect casualties of, an act of war, terrorism, or other attack, which could result in disruption of our ability to generate, purchase, transmit or distribute electricity for a significant period of time, otherwise disrupt our customer operations and/or result in incidents that could result in harmful effects on the environment and human health, including loss of life. Any such disruption or incident could result in a significant decrease in revenue, significant additional capital and operating costs, including costs to implement additional security systems or personnel to purchase electricity and to replace or repair our assets over and above any available insurance reimbursement, higher insurance deductibles, higher premiums and more restrictive insurance policies, legal claims or proceedings, greater regulation with higher attendant costs, generally, and significant damage to our reputation, which could have a material adverse effect on our business, results of operations and financial condition.
Capital Improvements and Construction Projects May Not be Completed Within Forecasted Budget, Schedule or Scope Parameters or Could be Canceled Which Could Adversely Affect Our Business and Results of Operations
Our business plan calls for execution of extensive capital investments in electric generation, transmission and distribution, including but not limited to our Energizing the Future transmission expansion program, which has been extended to include $4.0 to $4.8 billion in investments from 2018 through 2021. We may be exposed to the risk of substantial price increases in, or the adequacy or availability of, the costs of labor and materials used in construction, nonperformance of equipment and increased costs due to delays, including delays relating to the procurement of permits or approvals, adverse weather or environmental matters. We engage numerous contractors and enter into a large number of construction agreements to acquire the necessary materials and/or obtain the required construction-related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors’ inabilities to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. Also, because we enter into construction agreements for the necessary materials and to obtain the required construction related services, any cancellation by FirstEnergy of a construction agreement could result in significant termination payments or penalties. Any delays, increased costs or losses or cancellation of a construction project could adversely affect our business and results of operations, particularly if we are not permitted to recover any such costs in rates.
Changes in Technology and Regulatory Policies May Make Our Facilities Significantly Less Competitive and Adversely Affect Our Results of Operations
We primarily generate electricity at large central station generation facilities. This method results in economies of scale and lower unit costs than newer generation technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in newer generation technologies will make newer generation technologies more cost-effective, or that changes in regulatory policy will create benefits that otherwise make these newer generation technologies even more competitive with central station electricity production. Increased competition, whether from such advances in technologies or from changes in regulatory policy, could result in permanent reductions in our historical load, adversely impact scheduling of generation, and decrease sales and revenues from our existing generation assets, which could have a material adverse effect on our results of operations.

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Further, to the extent that newer generation technologies are connected directly to load, bypassing the transmission and distribution systems, potential impacts could include decreased transmission and distribution revenues, stranded assets and increased uncertainty in load forecasting and integrated resource planning and could adversely affect our business and results of operations.
Certain FirstEnergy Companies Have Guaranteed the Performance of Third Parties, Which May Result in Substantial Costs or the Incurrence of Additional Debt
Certain FirstEnergy companies have issued guarantees of the performance of others, which obligates such FirstEnergy companies to perform in the event that the third parties do not perform. For instance, FE is a guarantor under a syndicated senior secured term loan facility, under which Global Holding's outstanding principal balance is $275 million. In the event of non-performance by the third parties, FirstEnergy could incur substantial cost to fulfill this obligation and other obligations under such guarantees. Such performance guarantees could have a material adverse impact on our financial position and operating results.
Additionally, with respect to FEV's investment in Global Holding, it could require additional capital from its owners, including FEV, to fund operations and meet its obligations under its term loan facility. These capital requirements could be significant and if other partners do not fund the additional capital, resulting in FEV increasing its equity ownership and obtaining the ability to direct the significant activities of Global Holding, FEV may be required to consolidate Global Holding, increasing FirstEnergy's long-term debt by $275 million.
Energy Companies are Subject to Adverse Publicity Causing Less Favorable Regulatory and Legislative Outcomes Which Could have an Adverse Impact on Our Business
Energy companies, including FirstEnergy's utility subsidiaries, have been the subject of criticism on matters including the reliability of their distribution services and the speed with which they are able to respond to power outages, such as those caused by storm damage. Adverse publicity of this nature, as well as negative publicity associated with the operation or bankruptcy of nuclear and/or coal-fired facilities or proceedings seeking regulatory recoveries may cause less favorable legislative and regulatory outcomes and damage our reputation, which could have an adverse impact on our business.
Risks Associated With Regulation

Any Subsequent Modifications to, Denial of, or Delay in the Effectiveness of the PUCO’s Approval of the DMR Could Impose Significant Risks on FirstEnergy’s Operations and Materially and Adversely Impact the Credit Ratings, Results of Operations and Financial Condition of FirstEnergy
On October 12, 2016, the PUCO denied the Ohio Companies’ modified Rider RRS and, in accordance with the PUCO Staff’s recommendation, approved a new DMR providing for the collection of $204 million annually (grossed up for income taxes) for three years with a possible extension for an additional two years. Various parties have appealed the PUCO’s denial of subsequent applications for rehearing to the Ohio Supreme Court. Any subsequent modification to, denial of, or delay in the effectiveness of, the PUCO’s order approving the DMR could impose risks on our operations and materially and adversely impact the credit ratings, results of operations and financial condition of FirstEnergy.
Complex and Changing Government Regulations, Including Those Associated With Rates and Rate Cases and Restrictions and Prohibitions on Certain Business Dealings Could Have a Negative Impact on Our Business, Financial Condition, Results of Operations and Cash Flows
We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence our operating environment. Changes in, or reinterpretations of, existing laws or regulations, or the imposition of new laws or regulations, could require us to incur additional costs or change the way we conduct our business, and therefore could have a material adverse impact on our results of operations.
Our transmission and operating utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. Thus, the rates a utility is allowed to charge may be decreased as a result of actions taken by FERC or by a state regulatory commission in which the Utilities operate. Also, these rates may not be set to recover such utility's expenses at any given time. Additionally, there may also be a delay between the timing of when costs are incurred and when costs are recovered. For example, we may be unable to timely recover the costs for our energy efficiency investments or expenses and additional capital or lost revenues resulting from the implementation of aggressive energy efficiency programs. While rate regulation is premised on providing an opportunity to earn a reasonable return on invested capital and recovery of operating expenses, there can be no assurance that the applicable regulatory commission will determine that all of our costs have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner. Further, there can be no assurance that we will retain the expected recovery in future rate cases.
In addition, as a U.S. corporation, we are subject to U.S. laws, Executive Orders, and regulations administered and enforced by the U.S. Department of Treasury and the Department of Justice restricting or prohibiting business dealings in or with certain nations and with certain specially designated nationals (individuals and legal entities). If any of our existing or future operations or

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investments, including our joint venture investment in Signal Peak or our continued procurement of uranium from existing suppliers, are subsequently determined to involve such prohibited parties we could be in violation of certain covenants in our financing documents and unless we cease or modify such dealings, we could also be in violation of such U.S. laws, Executive Orders and sanctions regulations, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
State Rate Regulation May Delay or Deny Full Recovery of Costs and Impose Risks on Our Operations. Any Denial of or Delay in, Cost Recovery Could Have an Adverse Effect on Our Business, Results of Operations, Cash Flows and Financial Condition
Each of the Utilities' retail rates are set by its respective regulatory agency for utilities in the state in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC - through traditional, cost-based regulated utility ratemaking. As a result, any of the Utilities may not be permitted to recover its costs and, even if it is able to do so, there may be a significant delay between the time it incurs such costs and the time it is allowed to recover them. Factors that may affect outcomes in the distribution rate cases include: (i) the value of plant in service; (ii) authorized rate of return; (iii) capital structure (including hypothetical capital structures); (iv) depreciation rates; (v) the allocation of shared costs, including consolidated deferred income taxes and income taxes payable across the FirstEnergy utilities; (vi) regulatory approval of rate recovery mechanisms for capital spending programs (including for example accelerated deployment of smart meters); and (vii) the accuracy of forecasts used for ratemaking purposes in "future test year" cases.
FirstEnergy can provide no assurance that any base rate request filed by any of the Utilities will be granted in whole or in part. Any denial of, or delay in, any base rate request could restrict the applicable Utility from fully recovering its costs of service, may impose risks on its operations, and may negatively impact its results of operations, cash flows and financial condition. In addition, to the extent that any of the Utilities seeks rate increases after an extended period of frozen or capped rates, pressure may be exerted on the applicable legislators and regulators to take steps to control rate increases, including through some form of rate increase moderation, reduction or freeze. Any related public discourse and debate can increase uncertainty associated with the regulatory process, the level of rates and revenues that are ultimately obtained, and the ability of the Utility to recover costs. Such uncertainty may restrict operational flexibility and resources, and reduce liquidity and increase financing costs.
Federal Rate Regulation May Delay or Deny Full Recovery of Costs and Impose Risks on Our Operations. Any Denial or Reduction of, or Delay in Cost Recovery Could Have an Adverse Effect on Our Business, Results of Operations, Cash Flows and Financial Condition
FERC policy currently permits recovery of prudently-incurred costs associated with wholesale power rates and the expansion and updating of transmission infrastructure within its jurisdiction. If FERC were to adopt a different policy regarding recovery of transmission costs or if transmission needs do not continue or develop as projected, or if there is any resulting delay in cost recovery, our strategy of investing in transmission could be affected. If FERC were to lower the rate of return it has authorized for FirstEnergy's cost-based wholesale power rates or transmission investments and facilities, it could reduce future earnings and cash flows, and impact our financial condition.
There are multiple matters pending before FERC. There can be no assurance as to the outcome of these proceedings and an adverse result could have an adverse impact on FirstEnergy’s results of operations and business conditions.
The Business Operations of Our Subsidiaries That Sell Wholesale Power Are Subject to Regulation by FERC and Could be Adversely Affected by Such Regulation
FERC granted the Utilities and certain FirstEnergy generating subsidiaries authority to sell electric energy, capacity and ancillary services at market-based rates. These orders also granted waivers of certain FERC accounting, record-keeping and reporting requirements, as well as, for certain of these subsidiaries, waivers of the requirements to obtain FERC approval for issuances of securities. FERC’s orders that grant this market-based rate authority reserve with FERC the right to revoke or revise that authority if FERC subsequently determines that these companies can exercise market power in transmission or generation, or create barriers to entry, or have engaged in prohibited affiliate transactions. In the event that one or more of FirstEnergy's market-based rate authorizations were to be revoked or adversely revised, the affected FirstEnergy subsidiaries may be subject to sanctions and penalties, and would be required to file with FERC for authorization of individual wholesale sales transactions, which could involve costly and possibly lengthy regulatory proceedings and the loss of flexibility afforded by the waivers associated with the current market-based rate authorizations.
Energy Efficiency and Peak Demand Reduction Mandates and Energy Price Increases Could Negatively Impact Our Financial Results
A number of regulatory and legislative bodies have introduced requirements and/or incentives to reduce peak demand and energy consumption. Such conservation programs could result in load reduction and adversely impact our financial results in different ways. To the extent conservation results in reduced energy demand or significantly slows the growth in demand, the value of our competitive

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generation and other unregulated business activities could be adversely impacted. We currently have energy efficiency riders in place to recover the cost of these programs either at or near a current recovery time frame in the states where we operate.
Currently, only our Ohio Companies recover lost distribution revenues that result between distribution rate cases. In our regulated operations, conservation could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. We have already been adversely impacted by reduced electric usage due in part to energy conservation efforts such as the use of efficient lighting products such as CFLs, halogens and LEDs. We could also be adversely impacted if any future energy price increases result in a decrease in customer usage. We are unable to determine what impact, if any, conservation and increases in energy prices will have on our financial condition or results of operations.
Additionally, failure to meet regulatory or legislative requirements to reduce energy consumption or otherwise increase energy efficiency could result in penalties that could adversely affect our financial results.
Mandatory Renewable Portfolio Requirements Could Negatively Affect Our Costs and Have An Adverse Effect on Our Financial Condition and Results of Operations
Where federal or state legislation mandates the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal and such legislation does not also provide for adequate cost recovery, it could result in significant changes in our business, including material increases in REC purchase costs, purchased power costs and capital expenditures. Such mandatory renewable portfolio requirements may have an adverse effect on our financial condition and results of operations.
Changes in Local, State or Federal Tax Laws Applicable To Us or Adverse Audit Results or Tax Rulings, and Any Resulting Increases in Taxes and Fees, May Adversely Affect Our Results of Operations, Financial Condition and Cash Flows
FirstEnergy is subject to various local, state and federal taxes, including income, franchise, real estate, sales and use and employment-related taxes. We exercise significant judgment in calculating such tax obligations, booking reserves as necessary to reflect potential adverse outcomes regarding tax positions we have taken and utilizing tax benefits, such as carryforwards and credits. Additionally, various tax rate and fee increases may be proposed or considered in connection with such changes in local, state or federal tax law. We cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, or whether any such legislation or regulation will be passed by legislatures or regulatory bodies. Any such changes, or any adverse tax audit results or adverse tax rulings on positions taken by FirstEnergy or its subsidiaries could have a negative impact on its results of operations, financial condition and cash flows.
In addition, in December 2017, Congress passed the Tax Act. Details regarding the transition from the current tax code to new tax reforms are only beginning to emerge. We cannot predict whether, when or to what extent new tax regulations, interpretations or rulings will be issued, nor is the long-term impact of proposed tax reform clear. The reform of U.S. tax laws may be enacted in a manner that negatively impacts our results of operations, financial condition, business operations, earnings and is adverse to FE's shareholders. Furthermore, with respect to the Utilities and our transmission-owning affiliates, FirstEnergy cannot predict what, if any, response state regulatory commissions or FERC may have and the potential response of such authorities regarding the rates and charges of the Utilities and our transmission-owning affiliates.
The EPA is Conducting NSR Investigations at Generating Plants that We Currently or Formerly Owned, the Results of Which Could Negatively Impact Our Results of Operations and Financial Condition
We may be subject to risks from changing or conflicting interpretations of existing laws and regulations, including, for example, the applicability of the EPA's NSR programs. Under the CAA, modification of our generation facilities in a manner that results in increased emissions could subject our existing generation facilities to the far more stringent new source standards applicable to new generation facilities.
The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards during work considered by the companies to be routine maintenance. The EPA has investigated alleged violations of the NSR standards at certain of our existing and former generating facilities. We intend to vigorously pursue and defend our position, but we are unable to predict their outcomes. If NSR and similar requirements are imposed on our generation facilities, in addition to the possible imposition of fines, compliance could entail significant capital investments in pollution control technology, which could have an adverse impact on our business, results of operations, cash flows and financial condition.
Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with New Environmental Laws, Including Limitations on GHG Emissions, Could Adversely Affect Cash Flow and Profitability
Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs for, among other things, installation and operation of pollution control equipment, emissions monitoring and fees, remediation and permitting at our facilities. These expenditures have been significant in the past

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and may increase in the future. We may be forced to shut down other facilities or change their operating status, either temporarily or permanently, if we are unable to comply with these or other existing or new environmental requirements, or if the expenditures required to comply with such requirements are unreasonable.
For example, in December 2011, the EPA finalized MATS to establish emission standards for, among other things, mercury, PM and HCI, for electric generating units. The costs associated with MATS compliance, and other environmental laws, is substantial. As a result of a comprehensive review of FirstEnergy's coal-fired generating facilities in light of MATS and other expanded requirements, we deactivated twenty-six (26) older coal-fired generating units in 2012, 2013, and 2015.
Moreover, new environmental laws or regulations including, but not limited to CWA effluent limitations imposing more stringent water discharge regulations, or changes to existing environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures. Because of the deregulation of certain of our generation facilities, we cannot directly recover through rates additional costs incurred for such deregulated generation facilities. Our compliance strategy, including but not limited to, our assumptions regarding estimated compliance costs, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If we fail to comply with environmental laws and regulations or new interpretations of longstanding requirements, even if caused by factors beyond our control, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations.
At the international level, the Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide greenhouse gas emissions by 26 to 28 percent below 2005 levels by 2025 and in September 2016, joined in adopting the agreement reached on December 12, 2015 at the United Nations Framework Convention on Climate Change meetings in Paris. However, on June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the 2015 Paris Agreement. Due to the uncertainty of control technologies available to reduce GHG emissions, any other legal obligation that requires substantial reductions of GHG emissions could result in substantial additional costs, adversely affecting cash flow and profitability, and raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.
We Could be Exposed to Private Rights of Action Relating to Environmental Matters Seeking Damages Under Various State and Federal Law Theories Which Could Have an Adverse Impact on Our Results of Operations, Financial Condition and Business Operations
Private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other relief. For example, claims have been made against certain energy companies alleging that CO2 emissions from power generating facilities constitute a public nuisance under federal and/or state common law. While FirstEnergy is not a party to this litigation, it, and/or one of its subsidiaries, could be named in other actions making similar allegations. An unfavorable ruling in any such case could result in the need to make modifications to our coal-fired plants or reduce emissions, suspend operations or pay money damages or penalties. Adverse rulings in these or other types of actions could have an adverse impact on our results of operations and financial condition and could significantly impact our business operations.
Various Federal and State Water and Solid, Non-Hazardous and Hazardous Waste Regulations May Require Us to Make Material Capital Expenditures
In September 2015, the EPA finalized new, more stringent effluent limits for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water under the CWA. The EPA has also established performance standards under the CWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants, specifically, reducing impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) to a 12% annual average and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system) using site-specific controls based on studies to be submitted to permitting authorities. Depending on the implementation of impingement and entrainment performance standards by permitting authorities, the future costs of compliance with these standards may require material capital expenditures.
We Are or May be Subject to Environmental Liabilities, Including Costs of Remediation of Environmental Contamination at Current or Formerly Owned Facilities, Which Could Have a Material Adverse effect on Our Results of Operations and Financial Condition
We may be subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned or operated by us and of property contaminated by hazardous substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. We are currently involved in a number of proceedings relating to sites where hazardous substances have been released and we may be subject to additional proceedings in the future. We also have current or previous ownership interests in sites associated with the production of gas and the production and delivery of electricity for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Remediation activities associated with our former MGP operations are one source of such costs. Citizen groups or others may bring litigation over environmental issues including claims of various types, such as property damage, personal injury, and citizen challenges to compliance decisions on the enforcement of environmental requirements, such as opacity and

42




other air quality standards, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although we expect that they could be material.
In some cases, a third party who has acquired assets from us has assumed the liability we may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability or disputes its responsibility, a regulatory authority or injured person could attempt to hold us responsible, and our remedies against the transferee may be limited by the financial resources of the transferee.
We Are and May Become Subject to Legal Claims Arising from the Presence of Asbestos or Other Regulated Substances at Some of Our Facilities
We have been named as a defendant in pending asbestos litigations involving multiple plaintiffs and multiple defendants, in several states. The majority of these claims arise out of alleged past exposures by contractors (and in Pennsylvania, former employees) at both currently and formerly owned electric generation plants. In addition, asbestos and other regulated substances are, and may continue to be, present at currently owned facilities where suitable alternative materials are not available. We believe that any remaining asbestos at our facilities is contained and properly identified in accordance with applicable governmental regulations, including OSHA. The continued presence of asbestos and other regulated substances at these facilities, however, could result in additional actions being brought against us. This is further complicated by the fact that many diseases, such as mesothelioma and cancer, have long latency periods in which the disease process develops, thus making it impossible to accurately predict the types and numbers of such claims in the near future. While insurance coverages exist for many of these pending asbestos litigations, others have no such coverages, resulting in FirstEnergy being responsible for all defense expenditures, as well as any settlements or verdict payouts.
The Continuing Availability and Operation of Generating Units is Dependent on Retaining or Renewing the Necessary Licenses, Permits, and Operating Authority from Governmental Entities, Including the NRC
We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of any of these agencies and we are not assured that any such permits, approvals or certifications will be renewed.
The Risks Associated with Climate Change May Have an Adverse Impact on Our Business Operations, Operating Results and Cash Flows
Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Utilities' service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Climate change could also affect the availability of a secure and economical supply of water in some locations, which is essential for continued operation of generating plants. Further, as extreme weather conditions increase system stress, we may incur costs relating to additional system backup or service interruptions, and in some instances, we may be unable to recover such costs. For all of these reasons, these physical risks could have an adverse financial impact on our business operations, operating results and cash flows. Climate change poses other financial risks as well. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes may require us to invest in additional system assets and purchase additional power. Additionally, decreased energy use due to weather changes may affect our financial condition through decreased rates, revenues, margins or earnings.
Future Changes in Accounting Standards May Affect Our Reported Financial Results
The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially impact how we report our financial condition and results of operations. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial position.

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Risks Associated With Financing and Capital Structure

In the Event of Volatility or Unfavorable Conditions in the Capital and Credit Markets, Our Business, Including the Immediate Availability and Cost of Short-Term Funds for Liquidity Requirements, Our Ability to Meet Long-Term Commitments, Our Ability to Hedge Effectively Our Generation Portfolio and the Competitiveness and Liquidity of Energy Markets May be Adversely Affected, Which Could Negatively Impact Our Results of Operations, Cash Flows and Financial Condition
We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit provided by various financial institutions to support our hedging operations. We also deposit cash in short-term investments. In the event of volatility in the capital and credit markets, our ability to draw on our credit facilities and cash may be adversely affected. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. Any delay in our ability to access those funds, even for a short period of time, could have a material adverse effect on our results of operations and financial condition.
Should there be fluctuations in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant foreign or domestic financial institutions or foreign governments, our access to liquidity needed for our business could be adversely affected. Unfavorable conditions could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash.
Energy markets depend heavily on active participation by multiple counterparties, which could be adversely affected should there be disruptions in the capital and credit markets. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace those market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on our results of operations and cash flows.
Interest Rates and/or a Credit Rating Downgrade Could Negatively Affect Our or Our Subsidiaries' Financing Costs, Ability to Access Capital and Requirement to Post Collateral and the Ability to Continue Successfully Implementing Our Retail Sales Strategy
We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. Past disruptions in capital and credit markets have resulted in higher interest rates on new publicly issued debt securities, increased costs for certain of our variable interest rate debt securities and failed remarketings of variable interest rate tax-exempt debt issued to finance certain of our facilities. Similar future disruptions could increase our financing costs and adversely affect our results of operations. Also, interest rates could change as a result of economic or other events that are beyond our risk management processes. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs that our risk management positions were intended to hedge. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations.
We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. A downgrade in our or our subsidiaries' credit ratings from the nationally recognized credit rating agencies, particularly to a level below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as available letters of credit and other guarantees. A downgrade in our credit rating, or that of our subsidiaries, could also preclude certain retail customers from executing supply contracts with us and therefore impact our ability to successfully implement our retail sales strategy. Furthermore, a downgrade could increase the cost of such capital by causing us to incur higher interest rates and fees associated with such capital. A rating downgrade would increase our interest expense on certain of FirstEnergy's long-term debt obligations and would also increase the fees we pay on our various existing credit facilities, thus increasing the cost of our working capital. A rating downgrade could also impact our ability to grow our regulated businesses by substantially increasing the cost of, or limiting access to, capital.
Any Default by Customers or Other Counterparties Could Have a Material Adverse Effect on Our results of Operations and Financial Condition
We are exposed to the risk that counterparties that owe us money, power, fuel or other commodities could breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, which would cause our financial results to be diminished and we might incur losses. Some of our agreements contain provisions that require the counterparties to provide credit support to secure

44




all or part of their obligations to FirstEnergy or its subsidiaries. If the counterparties to these arrangements fail to perform, we may have a right to receive the proceeds from the credit support provided, however the credit support may not always be adequate to cover the related obligations. In such event, we may incur losses in addition to amounts, if any, already paid to the counterparties, including by being forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices. Although our estimates take into account the expected probability of default by a counterparty, our actual exposure to a default by customers or other counterparties may be greater than the estimates predict, which could have a material adverse effect on our results of operations and financial condition.
We Must Rely on Cash from Our Subsidiaries and Any Restrictions on Our Utility Subsidiaries' Ability to Pay Dividends or Make Cash Payments to Us May Adversely Affect Our Cash Flows and Financial Condition
We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our business is conducted by our subsidiaries. Consequently, our cash flow, including our ability to pay dividends and service debt, is dependent on the operating cash flows of our subsidiaries and their ability to upstream cash to the holding company. Any inability of our subsidiaries to pay dividends or make cash payments to us may adversely affect our cash flows and financial condition.
Additionally, our utility and transmission subsidiaries are regulated by various state utility and federal commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state and federal commissions could attempt to impose restrictions on the ability of our utility and transmission subsidiaries to pay dividends or otherwise restrict cash payments to us.
Our Mandatorily Convertible Preferred Stock Will be Converted into Common Stock, at the Latest, in Two Years from the Date of Issuance and the Holders Thereof Have Registration Rights. Upon Conversion of the Preferred Shares, the Number of Common Shares Eligible for Future Resale in the Public Market Will Increase and May Result in Dilution to Common Shareholders. This May Have an Adverse Effect on the Market Price of Common Stock.
On January 22, 2018, FE issued $2.5 billion of equity, which included $1.62 billion of mandatorily convertible preferred equity with an initial conversion price of $27.42 per share and $850 million of common equity issued at $28.22 per share. The issuance of common equity created some dilution to existing common holders. The new preferred shares contain an optional conversion for holders beginning in July 2018, and will mandatorily convert in 18 months from issuance, subject to limited exceptions.
Upon the conversion of the mandatorily convertible preferred stock additional shares of our common stock will be issued, which results in dilution to our stockholders, and will increase the number of shares eligible for resale in the public market. Sales of substantial numbers of such shares in the public market could adversely affect the market price of our common stock.

We Cannot Assure Common and Preferred Shareholders that Future Dividend Payments Will be Made, or if Made, in What Amounts They May be Paid

Our Board of Directors will continue to regularly evaluate our common stock dividend and determine an appropriate dividend each quarter taking into account such factors as, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common or preferred shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past. Further, the terms of the outstanding preferred stock require that preferred shareholders receive dividends alongside the common shareholders on an as-converted, pro rata basis.
The Recognition of Impairments of Goodwill and Long-Lived Assets Has Adversely Affected Our Results of Operations and Additional Impairments in the CES Segment Could Result Under Certain Circumstances In One or More Events of Default Under Various Agreements Related to the Indebtedness of FE and Have a Material Adverse Effect on FirstEnergy’s Business, Financial Condition, Results of Operations, Liquidity and the Trading Price of FirstEnergy's Securities
We have approximately $5.6 billion of goodwill on our consolidated balance sheet as of December 31, 2017. Goodwill is tested for impairment annually as of July 31 or whenever events or changes in circumstances indicate impairment may have occurred. Key assumptions incorporated in the estimated cash flows used for the impairment analysis requiring significant management judgment include: discount rates, growth rates, future energy and capacity pricing, projected operating income, changes in working capital, projected capital expenditures, projected funding of pension plans, expected results of future rate proceedings, the impact of pending carbon and other environmental legislation and terminal multiples.
We are unable to predict whether further impairments of one or more of our long-lived assets or investments may occur in the future. The actual timing and amounts of any impairments to goodwill, or long-lived assets in the future depends on many factors, including the outcome of the strategic review, interest rates, sector market performance, our capital structure, natural gas or other commodity prices, market prices for power, results of future rate proceedings, operating and capital expenditure requirements, the value of comparable acquisitions, environmental regulations and other factors. A determination that goodwill, a long-lived asset, or other investments are impaired would result in a non-cash charge that could materially adversely affect our results of operations and capitalization. Additionally, although the debt-to-total-capitalization ratio of FE’s credit facility excludes non-cash charges up to $5.5 billion related to asset impairments attributable to the power generation assets owned by FES, AE Supply and each of their

45




subsidiaries, the asset impairments recognized in 2016 fully utilized the $5.5 billion exclusion and charges beyond that amount will negatively impact the debt-to-total-capitalization covenant, which may have a material adverse effect on FirstEnergy’s business, financial condition, results of operations, liquidity and the trading price of FirstEnergy's securities.
ITEM 1B.
UNRESOLVED STAFF COMMENTS

None.
ITEM 2.
PROPERTIES

The first mortgage indentures for the Ohio Companies, Penn, MP, PE, WP, FG and NG constitute direct first liens on substantially all of the respective physical property, subject only to excepted encumbrances, as defined in the first mortgage indentures. See Note 7, "Leases," and Note 12, "Capitalization," of the Combined Notes to Consolidated Financial Statements for information concerning leases and financing encumbrances affecting certain of the Utilities’, FG’s and NG’s properties.

FirstEnergy controls the following generation sources as of January 31, 2018, shown in the table below. Except for the leasehold interests, OVEC participation and wind and solar power arrangements referenced in the footnotes to the table, substantially all of FES' competitive generating units are owned by NG (nuclear) and FG (non-nuclear); the regulated generating units are owned by JCP&L and MP.
 
 
 
 
 
 
Competitive
 
 
Plant (Location)
 
Unit
 
Total
 
FES
 
AE Supply
 
Regulated
 
 
 
 
Net Demonstrated Capacity (MW)
Super-critical Coal-fired:
 
 

 
 
 
 
 
 
 
 
Bruce Mansfield (Shippingport, PA)
 
1

 
830

(1)
830

 

 

Bruce Mansfield (Shippingport, PA)
 
2

 
830

 
830

 

 

Bruce Mansfield (Shippingport, PA)
 
3

 
830

 
830

 

 

Harrison (Haywood, WV)
 
1-3

 
1,984

 

 

 
1,984

Pleasants (Willow Island, WV)
 
1-2

 
1,300

(9)

 
1,300

 

W. H. Sammis (Stratton, OH)
 
6-7

 
1,200

  
1,200

 

 

Fort Martin (Maidsville, WV)
 
1-2

 
1,098

 

 

 
1,098

 
 
 
 
8,072

 
3,690

 
1,300

 
3,082

Sub-critical and Other Coal-fired:
 
 
 
 
 
 
 
 
 
 
W. H. Sammis (Stratton, OH)
 
1-5

 
1,010

(7)
1,010

 

 

Bay Shore (Toledo, OH)
 
1

 
136

(7)
136

 

 

OVEC (Cheshire, OH) (Madison, IN)
 
1-11

 
188

(2)
110

 
67

 
11

 
 
 

 
1,334

  
1,256

 
67

 
11

Nuclear:
 
 

 
 
  
 
 
 
 
 
Beaver Valley (Shippingport, PA)
 
1

 
939

 
939

 

 

Beaver Valley (Shippingport, PA)
 
2

 
933

 
933

 

 

Davis-Besse (Oak Harbor, OH)
 
1

 
908

 
908

 

 

Perry (N. Perry Village, OH)
 
1

 
1,268

 
1,268

 

 

 
 
 

 
4,048

  
4,048

 

 

Gas/Oil-fired: